2021Annual Report.pdf

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MATTHEWT. LARKIN
Revenue Requircment Senior Manager
[e-mail]
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April 1 5,2022
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, ldaho 83720-0074
Re: ldaho Power Company's2021Annual FERC Form 1 Report
Dear Ms. Noriyuki:
Pursuant to ldaho Code S 61.405, and Order No. 35058, attached for electronic filing
are ldaho Power Company's FERC Form 1 Report and ldaho Supplement for the year
ending December 31,202'1. Also included is the IDACORP 2021 Annual Report and the
2021 lndependent Audito/s Report.
lf you have any questions, please contact Regulatory Consultant Kelley Noe at
208-388-5736 or [e-mail].
Very truly yours,
Matthew T. Larkin
THIS FILING IS
Item 1: ☑ An Initial (Original) Submission OR ☐ Resubmission No.
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a),
304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in
criminal fines, civil penalties and other sanctions as provided by law. The
Federal Energy Regulatory Commission does not consider these reports to be
of confidential nature
Exact Legal Name of Respondent (Company)
Idaho Power Company
Year/Period of Report
End of: 2021/ Q4
FERC FORM NO. 1 (REV. 02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1).
FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting
requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities,
licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be
non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities,
Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. §
141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
one million megawatt hours of total annual sales,
100 megawatt hours of annual sales for resale,
500 megawatt hours of annual power exchanges delivered, or
500 megawatt hours of annual wheeling for others (deliveries plus losses).
What and Where to Submit
Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the
specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual
Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the
Commission at:
Secretary
Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426
For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers
classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the
Secretary of the Commission at the address above.
The CPA Certification Statement should:
Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable
Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting
releases), and
Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a
regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific
qualifications.)
Schedules Pages
Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the
letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have
reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the
year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the
Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting
releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we
considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below)
conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the
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INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-QGENERAL INFORMATIONPurposeFERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1).FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reportingrequirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities,licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to benon-confidential public use forms.Who Must SubmitEach Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities,Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. §141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:one million megawatt hours of total annual sales,100 megawatt hours of annual sales for resale,500 megawatt hours of annual power exchanges delivered, or500 megawatt hours of annual wheeling for others (deliveries plus losses).What and Where to SubmitSubmit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to thespecifications in the Form 1 and 3-Q taxonomies.The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest AnnualReport to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of theCommission at:SecretaryFederal Energy Regulatory Commission 888 First Street, NEWashington, DC 20426For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filersclassified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to theSecretary of the Commission at the address above.The CPA Certification Statement should:Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicableUniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accountingreleases), andBe signed by independent certified public accountants or an independent licensed public accountant certified or licensed by aregulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specificqualifications.)Schedules PagesComparative Balance Sheet 110-113Statement of Income 114-117Statement of Retained Earnings 118-119Statement of Cash Flows 120-121Notes to Financial Statements 122-123The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in theletter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we havereported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for theyear filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of theFederal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accountingreleases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as weconsidered necessary in the circumstances.Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below)
conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the
I.II.1.2.3.4.III.a.b.c.d.a.b.e.
applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the
pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further
instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-
efilingferc-online.
Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q
free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.
When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including
the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and
reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to
average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing
burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance
Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention:
Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information
does not display a valid control number (44 U.S.C. § 3512 (a)).
GENERAL INSTRUCTIONS
Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and
phrases in accordance with the USofA.
Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents
are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts
shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to
determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and
use for statement of income accounts the current year's year to date amounts.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and
completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on
the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to
be completed only for resubmissions (see VII. below).
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive.
Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically
authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the
report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to
remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the
Open Access Transmission Tariff. "Self" means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain
reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open
Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission
Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a
footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open
Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination
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applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of thepages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Furtherinstructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Qfree of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.When to SubmitFERC Forms 1 and 3-Q must be filed by the following schedule:FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), andFERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).Where to Send Comments on Public Reporting Burden.The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, includingthe time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing andreviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated toaverage 168 hours per response.Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducingburden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information ClearanceOfficer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention:Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of informationdoes not display a valid control number (44 U.S.C. § 3512 (a)).GENERAL INSTRUCTIONSPrepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words andphrases in accordance with the USofA.Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where centsare important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amountsshown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds todetermine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, anduse for statement of income accounts the current year's year to date amounts.Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly andcompletely states the fact.For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) onthe List of Schedules, pages 2 and 3.Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is tobe completed only for resubmissions (see VII. below).Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive.Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specificallyauthorized.Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by thereport of the previous period/year, or an appropriate explanation given as to why the different figures were used.Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended toremain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and theOpen Access Transmission Tariff. "Self" means the respondent.FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remainreliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the OpenAccess Transmission Tariff.LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that servicecannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point TransmissionReservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in afootnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open
Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination
f.g.IV.a.b.V.I.II.III.IV.V.VI.VII.VIII.IX.X.
date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations,
where the duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain
reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned
classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a
footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods.
Provide an explanation in a footnote for each adjustment.
DEFINITIONS
Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission.
Name the commission whose authorization was obtained and give date of the authorization.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is
made.
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.S.C. § 791a-825r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:
’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether
incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter
defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor
in interest thereof;
'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under
the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......
"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and
appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay
reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution
system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit
or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of
which are necessary or appropriate in the maintenance and operation of such unit;
"Sec. 4. The Commission is hereby authorized and empowered
'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the
water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity,
development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the
purposes of this Act."
"Sec. 304.
Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the
Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper
administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require
from such persons specific answers to all questions upon which the Commission may need information. The Commission may require
that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and
reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of
maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities,
depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such
person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless
the Commission otherwise specifies*.10
"Sec. 309.
The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and
regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations
may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements,
declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which
they shall be field..."
GENERAL PENALTIES
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11.
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date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations,where the duration of each period of reservation is less than one-year.NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remainreliable even under adverse conditions.OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentionedclassifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in afootnote for each entry.AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods.Provide an explanation in a footnote for each adjustment.DEFINITIONSCommission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission.Name the commission whose authorization was obtained and give date of the authorization.Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report ismade.EXCERPTS FROM THE LAWFederal Power Act, 16 U.S.C. § 791a-825rSec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whetherincorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafterdefined;'Person' means an individual or a corporation;'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successorin interest thereof;'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent underthe Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams andappurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bayreservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distributionsystem or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unitor any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy ofwhich are necessary or appropriate in the maintenance and operation of such unit;"Sec. 4. The Commission is hereby authorized and empowered'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, thewater-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity,development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for thepurposes of this Act.""Sec. 304.Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as theCommission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the properadministration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and requirefrom such persons specific answers to all questions upon which the Commission may need information. The Commission may requirethat such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, andreduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost ofmaintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities,depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any suchperson to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unlessthe Commission otherwise specifies*.10"Sec. 309.The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules andregulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulationsmay define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements,declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within whichthey shall be field..."
GENERAL PENALTIES
I.II.3.4.5.7.11.a.a.
The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).
FERC FORM NO. 1 (ED. 03-07)
The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).FERC FORM NO. 1 (ED. 03-07)
FERC FORM NO. 1
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
Idaho Power Company
02 Year/ Period of Report
End of: 2021/ Q4
03 Previous Name and Date of Change (If name changed during year)
/
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
05 Name of Contact Person
Ken Petersen
06 Title of Contact Person
VP, CAO&Treasurer
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
08 Telephone of Contact Person, Including Area Code
[phone]
09 This Report is An Original / A Resubmission
(1) ☑ An Original
(2) ☐ A Resubmission
10 Date of Report (Mo, Da, Yr)
04/15/2022
Annual Corporate Officer Certification
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct
statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report,
conform in all material respects to the Uniform System of Accounts.
01 Name
Ken Petersen
02 Title
VP, Controller, CAO & Treasurer
03 Signature
Ken Petersen
04 Date Signed (Mo, Da, Yr)
04/15/2022
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States
any false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No. 1 (REV. 02-04)
Page 1
FERC FORM NO. 1REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHERIDENTIFICATION01 Exact Legal Name of RespondentIdaho Power Company 02 Year/ Period of ReportEnd of: 2021/ Q403 Previous Name and Date of Change (If name changed during year)/ 04 Address of Principal Office at End of Period (Street, City, State, Zip Code)1221 W Idaho St, P.O. Box 70 Boise, Id 83707-007005 Name of Contact PersonKen Petersen 06 Title of Contact PersonVP, CAO&Treasurer07 Address of Contact Person (Street, City, State, Zip Code)1221 W Idaho St, P.O. Box 70 Boise, Id 83707-007008 Telephone of Contact Person, Including Area Code(208) 388-2761 09 This Report is An Original / A Resubmission(1) ☑ An Original(2) ☐ A Resubmission 10 Date of Report (Mo, Da, Yr)04/15/2022Annual Corporate Officer CertificationThe undersigned officer certifies that:I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correctstatements of the business affairs of the respondent and the financial statements, and other financial information contained in this report,conform in all material respects to the Uniform System of Accounts.01 NameKen Petersen02 TitleVP, Controller, CAO & Treasurer 03 SignatureKen Petersen 04 Date Signed (Mo, Da, Yr)04/15/2022Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United Statesany false, fictitious or fraudulent statements as to any matter within its jurisdiction.FERC FORM No. 1 (REV. 02-04)Page 1
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
LIST OF SCHEDULES (Electric Utility)
Line
No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
Identification 1
List of Schedules 2
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Information on Formula Rates 106
7 Important Changes During the Year 108
8 Comparative Balance Sheet 110
9 Statement of Income for the Year 114
10 Statement of Retained Earnings for the Year 118
12 Statement of Cash Flows 120
12 Notes to Financial Statements 122
13 Statement of Accum Other Comp Income, Comp
Income, and Hedging Activities 122a
14 Summary of Utility Plant & Accumulated Provisions
for Dep, Amort & Dep 200
15 Nuclear Fuel Materials 202 NA
16 Electric Plant in Service 204
17 Electric Plant Leased to Others 213 NA
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric
Utility Plant 219
21 Investment of Subsidiary Companies 224
22 Materials and Supplies 227
23 Allowances 228 NA
24 Extraordinary Property Losses 230a NA
25 Unrecovered Plant and Regulatory Study Costs 230b NA
26 Transmission Service and Generation
Interconnection Study Costs 231
FERC FORM No. 1 (ED. 12-96)
Page 2
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4LIST OF SCHEDULES (Electric Utility)LineNo.Title of Schedule(a)Reference Page No.(b)Remarks(c)Identification 1List of Schedules 21General Information 1012Control Over Respondent 1023Corporations Controlled by Respondent 1034Officers1045Directors1056Information on Formula Rates 1067Important Changes During the Year 1088Comparative Balance Sheet 1109Statement of Income for the Year 11410Statement of Retained Earnings for the Year 11812Statement of Cash Flows 12012Notes to Financial Statements 12213Statement of Accum Other Comp Income, CompIncome, and Hedging Activities 122a14Summary of Utility Plant & Accumulated Provisionsfor Dep, Amort & Dep 20015Nuclear Fuel Materials 202 NA16Electric Plant in Service 20417Electric Plant Leased to Others 213 NA18Electric Plant Held for Future Use 21419Construction Work in Progress-Electric 21620Accumulated Provision for Depreciation of ElectricUtility Plant 21921Investment of Subsidiary Companies 22422Materials and Supplies 22723Allowances228 NA24Extraordinary Property Losses 230a NA25Unrecovered Plant and Regulatory Study Costs 230b NA26Transmission Service and GenerationInterconnection Study Costs 231
FERC FORM No. 1 (ED. 12-96)
Page 2
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capital Stock 250
31 Other Paid-in Capital 253
32 Capital Stock Expense 254b
33 Long-Term Debt 256
34 Reconciliation of Reported Net Income with Taxable
Inc for Fed Inc Tax 261
35 Taxes Accrued, Prepaid and Charged During the
Year 262
36 Accumulated Deferred Investment Tax Credits 266
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated
Amortization Property 272 NA
39 Accumulated Deferred Income Taxes-Other Property 274
40 Accumulated Deferred Income Taxes-Other 276
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300
43 Regional Transmission Service Revenues (Account
457.1)302 NA
44 Sales of Electricity by Rate Schedules 304
45 Sales for Resale 310
46 Electric Operation and Maintenance Expenses 320
47 Purchased Power 326
48 Transmission of Electricity for Others 328
49 Transmission of Electricity by ISO/RTOs 331 NA
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant
(Account 403, 404, 405)336
53 Regulatory Commission Expenses 350
54 Research, Development and Demonstration
Activities 352
55 Distribution of Salaries and Wages 354
LIST OF SCHEDULES (Electric Utility)
Line
No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
FERC FORM No. 1 (ED. 12-96)
Page 2
27 Other Regulatory Assets 23228Miscellaneous Deferred Debits 23329Accumulated Deferred Income Taxes 23430Capital Stock 25031Other Paid-in Capital 25332Capital Stock Expense 254b33Long-Term Debt 25634Reconciliation of Reported Net Income with TaxableInc for Fed Inc Tax 26135Taxes Accrued, Prepaid and Charged During theYear 26236Accumulated Deferred Investment Tax Credits 26637Other Deferred Credits 26938Accumulated Deferred Income Taxes-AcceleratedAmortization Property 272 NA39Accumulated Deferred Income Taxes-Other Property 27440Accumulated Deferred Income Taxes-Other 27641Other Regulatory Liabilities 27842Electric Operating Revenues 30043Regional Transmission Service Revenues (Account457.1)302 NA44Sales of Electricity by Rate Schedules 30445Sales for Resale 31046Electric Operation and Maintenance Expenses 32047Purchased Power 32648Transmission of Electricity for Others 32849Transmission of Electricity by ISO/RTOs 331 NA50Transmission of Electricity by Others 33251Miscellaneous General Expenses-Electric 33552Depreciation and Amortization of Electric Plant(Account 403, 404, 405)33653Regulatory Commission Expenses 35054Research, Development and DemonstrationActivities 35255Distribution of Salaries and Wages 354LIST OF SCHEDULES (Electric Utility)LineNo.Title of Schedule(a)Reference Page No.(b)Remarks(c)
FERC FORM No. 1 (ED. 12-96)
Page 2
56 Common Utility Plant and Expenses 356 NA
57 Amounts included in ISO/RTO Settlement
Statements 397 NA
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a NA
61 Electric Energy Account 401a
62 Monthly Peaks and Output 401b
63 Steam Electric Generating Plant Statistics 402
64 Hydroelectric Generating Plant Statistics 406
65 Pumped Storage Generating Plant Statistics 408 NA
66 Generating Plant Statistics Pages 410
0 Energy Storage Operations (Large Plants)414 NA
67 Transmission Line Statistics Pages 422
68 Transmission Lines Added During Year 424
69 Substations 426
70 Transactions with Associated (Affiliated) Companies 429
71 Footnote Data 450
Stockholders' Reports (check appropriate box)
Stockholders' Reports Check appropriate box:
☐ Two copies will be submitted
☐ No annual report to stockholders is prepared
FERC FORM No. 1 (ED. 12-96)
Page 2
LIST OF SCHEDULES (Electric Utility)
Line
No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
56 Common Utility Plant and Expenses 356 NA57Amounts included in ISO/RTO SettlementStatements 397 NA58Purchase and Sale of Ancillary Services 39859Monthly Transmission System Peak Load 40060Monthly ISO/RTO Transmission System Peak Load 400a NA61Electric Energy Account 401a62Monthly Peaks and Output 401b63Steam Electric Generating Plant Statistics 40264Hydroelectric Generating Plant Statistics 40665Pumped Storage Generating Plant Statistics 408 NA66Generating Plant Statistics Pages 4100Energy Storage Operations (Large Plants)414 NA67Transmission Line Statistics Pages 42268Transmission Lines Added During Year 42469Substations42670Transactions with Associated (Affiliated) Companies 42971Footnote Data 450Stockholders' Reports (check appropriate box)Stockholders' Reports Check appropriate box:☐ Two copies will be submitted☐ No annual report to stockholders is prepared FERC FORM No. 1 (ED. 12-96)Page 2LIST OF SCHEDULES (Electric Utility)LineNo.Title of Schedule(a)Reference Page No.(b)Remarks(c)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general
corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general
corporate books are kept.
Ken Petersen Vice President, CAO & Treasurer, Idaho Power Company 1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
Ken Petersen
Vice President, CAO & Treasurer
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a
special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.
Idaho, June 30, 1989
State of Incorporation: ID
Date of Incorporation: 1989-06-30
Incorporated Under Special Law:
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date
such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when
possession by receiver or trustee ceased.
(a) Name of Receiver or Trustee Holding Property of the Respondent:
(b) Date Receiver took Possession of Respondent Property:
(c) Authority by which the Receivership or Trusteeship was created:
(d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.
Class of Utility Service State Electric Idaho Electric Oregon
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for
your previous year's certified financial statements?
(1) ☐ Yes
(2) ☑ No
FERC FORM No. 1 (ED. 12-87)
Page 101
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4GENERAL INFORMATION1. Provide name and title of officer having custody of the general corporate books of account and address of office where the generalcorporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the generalcorporate books are kept.Ken Petersen Vice President, CAO & Treasurer, Idaho Power Company 1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070Ken PetersenVice President, CAO & Treasurer1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-00702. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under aspecial law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.Idaho, June 30, 1989State of Incorporation: IDDate of Incorporation: 1989-06-30Incorporated Under Special Law: 3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) datesuch receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date whenpossession by receiver or trustee ceased.(a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased: 4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.Class of Utility Service State Electric Idaho Electric Oregon5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant foryour previous year's certified financial statements?(1) ☐ Yes (2) ☑ NoFERC FORM No. 1 (ED. 12-87)Page 101
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at
the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control
was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was
held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.
IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
FERC FORM No. 1 (ED. 12-96)
Page 102
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4CONTROL OVER RESPONDENT1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent atthe end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If controlwas in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control washeld by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.IDACORP owns 100% of Idaho Power Company's Common Stock.IDACORP is a public utility Holding Company incorporated effective 10-1-1998FERC FORM No. 1 (ED. 12-96)Page 102
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
CORPORATIONS CONTROLLED BY RESPONDENT
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent
Voting Stock
Owned
(c)
Footnote Ref.
(d)
1 Direct Control
2 Idaho Energy Resources Company Coal mining and mineral 100%
3 development
FERC FORM No. 1 (ED. 12-96)
Page 103
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4CORPORATIONS CONTROLLED BY RESPONDENTLineNo.Name of Company Controlled(a)Kind of Business(b)PercentVoting StockOwned(c)Footnote Ref.(d)1 Direct Control2Idaho Energy Resources Company Coal mining and mineral 100%3 developmentFERC FORM No. 1 (ED. 12-96)Page 103
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
OFFICERS
Line
No.
Title
(a)
Name of Officer
(b)
Salary for Year
(c)
Date Started in
Period
(d)
Date Ended in
Period
(e)
1 President & CEO Idaho Power
Company Lisa Grow 775,000
2 Senior Vice President, CFO Steven R. Keen 497,000
3 Senior Vice President, COO Adam J. Richins 440,000
4 Senior Vice President & General
Counsel Brian R. Buckham 420,000
5 Senior Vice President, Public
Affairs Jeffery L. Malmen 350,000
6 Vice President, CAO &
Treasurer Ken W. Petersen 310,000
7 Vice President, Regulatory
Affairs Tim Tatum 257,500
8 Vice President, Power Supply Ryan N. Adelman 247,500
9 Vice President, Human
Resources Sarah E. Griffin 247,500
10 Corporate Secretary Patrick Harrington 245,000
11 Vice President, Customer
Operations & CSO Bo Hanchey 242,000
12 Vice President, Corporate
Services & Communications Debra H. Leithauser 232,000
13 Vice President, Information
Technology & CIO Jason C. Huszar 225,500
14 Vice President, Planning,
Engineering & Construction Mitch Colburn 220,000
FERC FORM No. 1 (ED. 12-96)
Page 104
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4OFFICERSLineNo.Title(a)Name of Officer(b)Salary for Year(c)Date Started inPeriod(d)Date Ended inPeriod(e)1 President & CEO Idaho PowerCompany Lisa Grow 775,0002Senior Vice President, CFO Steven R. Keen 497,0003Senior Vice President, COO Adam J. Richins 440,0004Senior Vice President & GeneralCounsel Brian R. Buckham 420,0005Senior Vice President, PublicAffairs Jeffery L. Malmen 350,0006Vice President, CAO &Treasurer Ken W. Petersen 310,0007Vice President, RegulatoryAffairs Tim Tatum 257,5008Vice President, Power Supply Ryan N. Adelman 247,5009Vice President, HumanResources Sarah E. Griffin 247,50010Corporate Secretary Patrick Harrington 245,00011Vice President, CustomerOperations & CSO Bo Hanchey 242,00012Vice President, CorporateServices & Communications Debra H. Leithauser 232,00013Vice President, InformationTechnology & CIO Jason C. Huszar 225,50014Vice President, Planning,Engineering & Construction Mitch Colburn 220,000FERC FORM No. 1 (ED. 12-96)Page 104
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
DIRECTORS
Line
No.
Name (and Title) of Director
(a)
Principal Business Address
(b)
Member of the Executive
Committee
(c)
Chairman of the Executive
Committee
(d)
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in
column (a), name and abbreviated titles of the directors who are officers of the respondent.
2. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of
the Executive Committee in column (d).
1 Darrell T. Anderson 1528 E Garden Brook Drive,
Eagle, Idaho 83616 false false
2 Odette C. Bolano 1055 N. Curtis Rd., Boise,
Idaho 83706 false false
3 Thomas E. Carlile 611 S 8th Street, Unit 503,
Boise, Idaho 83702 false false
4
(a)
Richard J. Dahl, Board Chair
(1)
PO Box 2052, McCall, Idaho
83638 true false
5 Annette G. Elg 3475 E Rivernest Lane, Boise,
ID 83706 false false
6 Lisa A. Grow, President and
CEO
Idaho Power Company, 1221
W. Idaho Street, PO Box 70,
Boise, ID 83707
true true
7 Ronald W. Jibson 417 Aerie Circle, North Salt
Lake, Utah 84054 false false
8
(b)
Judith A. Johansen, Comp
Committee Chair (2)
10446 E. Palo Brea Dr,
Scottsdale, Arizona 85262 true false
9
(c)
Dennis L. Johnson, Corp Gov.
Chair (3)
926 West Oakhampton Drive,
Eagle, Idaho 83616 true false
10
(d)
Christine King, Comp.
Committee Chair (4)
8527 East Old Field Rd.,
Scottsdale, Arizona 85266 true false
11 Richard J. Navarro, Audit Chair 1256 E Candleridge Ct., Boise,
Idaho 83712 true false
12
(e)
Dr. Mark Peters (5)
884 Neil Avenue, Columbus,
Ohio 43215 false false
FERC FORM No. 1 (ED. 12-95)
Page 105
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4DIRECTORSLineNo.Name (and Title) of Director(a)Principal Business Address(b)Member of the ExecutiveCommittee(c)Chairman of the ExecutiveCommittee(d)1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include incolumn (a), name and abbreviated titles of the directors who are officers of the respondent.2. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman ofthe Executive Committee in column (d).1 Darrell T. Anderson 1528 E Garden Brook Drive,Eagle, Idaho 83616 false false2Odette C. Bolano 1055 N. Curtis Rd., Boise,Idaho 83706 false false3Thomas E. Carlile 611 S 8th Street, Unit 503,Boise, Idaho 83702 false false4(a)Richard J. Dahl, Board Chair(1)PO Box 2052, McCall, Idaho83638 true false5Annette G. Elg 3475 E Rivernest Lane, Boise,ID 83706 false false6Lisa A. Grow, President andCEO Idaho Power Company, 1221W. Idaho Street, PO Box 70,Boise, ID 83707 true true7Ronald W. Jibson 417 Aerie Circle, North SaltLake, Utah 84054 false false8(b)Judith A. Johansen, CompCommittee Chair (2)10446 E. Palo Brea Dr,Scottsdale, Arizona 85262 true false9(c)Dennis L. Johnson, Corp Gov.Chair (3)926 West Oakhampton Drive,Eagle, Idaho 83616 true false10(d)Christine King, Comp.Committee Chair (4)8527 East Old Field Rd.,Scottsdale, Arizona 85266 true false11Richard J. Navarro, Audit Chair 1256 E Candleridge Ct., Boise,Idaho 83712 true false12(e)Dr. Mark Peters (5)884 Neil Avenue, Columbus,Ohio 43215 false falseFERC FORM No. 1 (ED. 12-95)Page 105
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: NameAndTitleOfDirector
Schedule Page: 105 Line No: 4 Column: a
(1) Stepped down as Corp Gov. Chair on May 20, 2021
(b) Concept: NameAndTitleOfDirector
Schedule Page: 105 Line No: 8 Column: a
(2) Appointed as a member of Executive Board and as Comp Committee Chair on May 20, 2021
(c) Concept: NameAndTitleOfDirector
Schedule Page: 105 Line No: 9 Column: a
(3) Appointed as a member of Executive Board and as Corp Gov. Chair on May 20, 2021
(d) Concept: NameAndTitleOfDirector
Schedule Page: 105 Line No: 10 Column: a
(4) Retired from board and as Comp Committee Chair on May 20, 2021
(e) Concept: NameAndTitleOfDirector
Schedule Page: 105 Line No: 12 Column: a
(5) Appointed to the Board on February 10, 2021
FERC FORM No. 1 (ED. 12-95)
Page 105
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4FOOTNOTE DATA(a) Concept: NameAndTitleOfDirectorSchedule Page: 105 Line No: 4 Column: a(1) Stepped down as Corp Gov. Chair on May 20, 2021(b) Concept: NameAndTitleOfDirectorSchedule Page: 105 Line No: 8 Column: a(2) Appointed as a member of Executive Board and as Comp Committee Chair on May 20, 2021(c) Concept: NameAndTitleOfDirectorSchedule Page: 105 Line No: 9 Column: a(3) Appointed as a member of Executive Board and as Corp Gov. Chair on May 20, 2021(d) Concept: NameAndTitleOfDirectorSchedule Page: 105 Line No: 10 Column: a(4) Retired from board and as Comp Committee Chair on May 20, 2021(e) Concept: NameAndTitleOfDirectorSchedule Page: 105 Line No: 12 Column: a(5) Appointed to the Board on February 10, 2021FERC FORM No. 1 (ED. 12-95)Page 105
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
INFORMATION ON FORMULA RATES
Line
No.
FERC Rate Schedule or Tariff Number
(a)
FERC Proceeding
(b)
Does the respondent have formula rates?
☑ Yes
☐ No
1 FERC Electric Tariff
FERC FORM No. 1 (NEW. 12-08)
Page 106
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4INFORMATION ON FORMULA RATESLineNo.FERC Rate Schedule or Tariff Number(a)FERC Proceeding(b)Does the respondent have formula rates?☑ Yes☐ No1FERC Electric TariffFERC FORM No. 1 (NEW. 12-08)Page 106
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Line
No.
Accession
No.
(a)
Document Date /
Filed Date
(b)
Docket No.
(c)
Description
(d)
Formula Rate FERC Rate
Schedule Number or Tariff
Number
(e)
Does the respondent file with the
Commission annual (or more
frequent) filings containing the inputs
to the formula rate(s)?
☑ Yes
☐ No
1 20210827-
5103 08/27/2021 ER09-1641-000
Idaho Power Company 2021
Annual Informational filing
under ER09-1641-000
FERC Electric Tariff
FERC FORM NO. 1 (NEW. 12-08)
Page 106a
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC ProceedingLineNo.AccessionNo.(a)Document Date /Filed Date(b)Docket No.(c)Description(d)Formula Rate FERC RateSchedule Number or TariffNumber(e)Does the respondent file with theCommission annual (or morefrequent) filings containing the inputsto the formula rate(s)?☑ Yes☐ No120210827-5103 08/27/2021 ER09-1641-000 Idaho Power Company 2021Annual Informational filingunder ER09-1641-000 FERC Electric TariffFERC FORM NO. 1 (NEW. 12-08)Page 106a
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
INFORMATION ON FORMULA RATES - Formula Rate Variances
Line
No.
Page No(s).
(a)
Schedule
(b)
Column
(c)
Line
No.
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
FERC FORM No. 1 (NEW. 12-08)
Page 106b
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/15/2022 Year/Period of ReportEnd of: 2021/ Q4INFORMATION ON FORMULA RATES - Formula Rate VariancesLineNo.Page No(s).(a)Schedule(b)Column(c)LineNo.(d)1234567891011121314151617181920212223242526272829
FERC FORM No. 1 (NEW. 12-08)
Page 106b
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM No. 1 (NEW. 12-08)
Page 106b
INFORMATION ON FORMULA RATES - Formula Rate Variances
Line
No.
Page No(s).
(a)
Schedule
(b)
Column
(c)
Line
No.
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance
with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers
an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred
during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent
please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to
which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash
management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
1. None
2. None
3. None
4. None
5. None
6. None
7. None
8. Effective 12/25/2021, a 6% general wage adjustment was implemented.
9. None
10. None
11. Reserved
12. None
13. Officer Changes in 2021: NONE
Director Changes in 2021:
Dr. Mark Peters was appointed to the Board on February 10, 2021.
Chris King retired from the board on May 20, 2021.
14. Idaho Power and its unregulated parent, IDACORP have separate cash management programs (separate bank accounts, liquidity facilities, short-term debt and investment programs).
No money has been loaned or advanced from Idaho Power to IDACORP through a cash management program.
FERC FORM No. 1 (ED. 12-96)
Page 108-109
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1 UTILITY PLANT
2 Utility Plant (101-106, 114)200 6,514,123,678 6,287,898,779
3 Construction Work in Progress (107)200 671,424,756 597,151,634
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)7,185,548,434 6,885,050,413
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108,
110, 111, 115)200 2,483,620,791 2,376,165,417
6 Net Utility Plant (Enter Total of line 4 less 5)4,701,927,643 4,508,884,996
7 Nuclear Fuel in Process of Ref., Conv., Enrich.,
and Fab. (120.1)202
8 Nuclear Fuel Materials and Assemblies-Stock
Account (120.2)
9 Nuclear Fuel Assemblies in Reactor (120.3)
10 Spent Nuclear Fuel (120.4)
11 Nuclear Fuel Under Capital Leases (120.6)
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel
Assemblies (120.5)202
13 Net Nuclear Fuel (Enter Total of lines 7-11 less
12)0
14 Net Utility Plant (Enter Total of lines 6 and 13)4,701,927,643 4,508,884,996
15 Utility Plant Adjustments (116)
16 Gas Stored Underground - Noncurrent (117)
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (121)3,646,749 5,125,740
19 (Less) Accum. Prov. for Depr. and Amort. (122)0 3,613
20 Investments in Associated Companies (123)0
21 Investment in Subsidiary Companies (123.1)224 27,909,478 33,918,130
23 Noncurrent Portion of Allowances 228
24 Other Investments (124)0
25 Sinking Funds (125)0
26 Depreciation Fund (126)
27 Amortization Fund - Federal (127)
28 Other Special Funds (128)56,140,386 50,732,850
FERC FORM No. 1 (REV. 12-03)
Page 110-111
29 Special Funds (Non Major Only) (129)
30 Long-Term Portion of Derivative Assets (175)890,345
31 Long-Term Portion of Derivative Assets - Hedges
(176)0
32 TOTAL Other Property and Investments (Lines
18-21 and 23-31)88,586,958 89,773,107
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only)
(130)
35 Cash (131)49,369,572 125,554,315
36 Special Deposits (132-134)1,830,847 2,702,913
37 Working Fund (135)13,000 11,500
38 Temporary Cash Investments (136)10,392,659 40,038,009
39 Notes Receivable (141)0
40 Customer Accounts Receivable (142)83,325,175 77,599,924
41 Other Accounts Receivable (143)12,806,869 10,223,384
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit
(144)5,015,917 5,263,704
43 Notes Receivable from Associated Companies
(145)6,169,545 10,088,722
44 Accounts Receivable from Assoc. Companies
(146)0
45 Fuel Stock (151)227 18,045,117 31,645,944
46 Fuel Stock Expenses Undistributed (152)227 0
47 Residuals (Elec) and Extracted Products (153)227
48 Plant Materials and Operating Supplies (154)227 73,329,824 62,178,340
49 Merchandise (155)227
50 Other Materials and Supplies (156)227 0
51 Nuclear Materials Held for Sale (157)202/227
52 Allowances (158.1 and 158.2)228
53 (Less) Noncurrent Portion of Allowances 228
54 Stores Expense Undistributed (163)227 4,221,832 2,762,521
55 Gas Stored Underground - Current (164.1)
56 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
FERC FORM No. 1 (REV. 12-03)
Page 110-111
57 Prepayments (165)24,557,592 20,057,116
58 Advances for Gas (166-167)
59 Interest and Dividends Receivable (171)6,639 20,129
60 Rents Receivable (172)
61 Accrued Utility Revenues (173)74,842,947 72,461,180
62 Miscellaneous Current and Accrued Assets (174)
63 Derivative Instrument Assets (175)6,598,152 1,995,125
64 (Less) Long-Term Portion of Derivative
Instrument Assets (175)890,345
65 Derivative Instrument Assets - Hedges (176)0
66 (Less) Long-Term Portion of Derivative
Instrument Assets - Hedges (176)0
67 Total Current and Accrued Assets (Lines 34
through 66)359,603,508 452,075,418
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)15,341,796 16,434,065
70 Extraordinary Property Losses (182.1)230a
71 Unrecovered Plant and Regulatory Study Costs
(182.2)230b
72 Other Regulatory Assets (182.3)232 1,533,747,521 1,558,894,709
73 Prelim. Survey and Investigation Charges
(Electric) (183)291,336
74 Preliminary Natural Gas Survey and
Investigation Charges 183.1)
75 Other Preliminary Survey and Investigation
Charges (183.2)
76 Clearing Accounts (184)3,092,658 572,323
77 Temporary Facilities (185)0
78 Miscellaneous Deferred Debits (186)233 75,436,950 73,302,886
79 Def. Losses from Disposition of Utility Plt. (187)
80 Research, Devel. and Demonstration Expend.
(188)352 0
81 Unamortized Loss on Reaquired Debt (189)39,557,636 42,496,351
82 Accumulated Deferred Income Taxes (190)234 324,688,128 343,510,457
83 Unrecovered Purchased Gas Costs (191)
84 Total Deferred Debits (lines 69 through 83)1,992,156,025 2,035,210,791
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
FERC FORM No. 1 (REV. 12-03)
Page 110-111
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)7,142,274,134 7,085,944,312
FERC FORM No. 1 (REV. 12-03)
Page 110-111
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250 97,877,030 97,877,030
3 Preferred Stock Issued (204)250 0
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207)712,257,435 712,257,435
7 Other Paid-In Capital (208-211)253 0
8 Installments Received on Capital Stock (212)252
9 (Less) Discount on Capital Stock (213)254
10 (Less) Capital Stock Expense (214)254b 2,096,925 2,096,924
11 Retained Earnings (215, 215.1, 216)118 1,670,857,887 1,567,699,558
12 Unappropriated Undistributed Subsidiary
Earnings (216.1)118 25,446,384 31,455,036
13 (Less) Reaquired Capital Stock (217)250 0
14 Noncorporate Proprietorship (Non-major only)
(218)
15 Accumulated Other Comprehensive Income
(219)122(a)(b)(40,039,894)(43,357,680)
16 Total Proprietary Capital (lines 2 through 15)2,464,301,917 2,363,834,455
17 LONG-TERM DEBT
18 Bonds (221)256 1,970,460,000 1,970,460,000
19 (Less) Reaquired Bonds (222)256 0
20 Advances from Associated Companies (223)256
21 Other Long-Term Debt (224)256 19,885,000 19,885,000
22 Unamortized Premium on Long-Term Debt (225)28,965,492 30,072,454
23 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)3,328,774 3,569,137
24 Total Long-Term Debt (lines 18 through 23)2,015,981,718 2,016,848,317
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent
(227)
27 Accumulated Provision for Property Insurance
(228.1)
FERC FORM No. 1 (REV. 12-03)
Page 112-113
28 Accumulated Provision for Injuries and Damages
(228.2)3,729,566 2,484,902
29 Accumulated Provision for Pensions and
Benefits (228.3)521,815,572 634,271,974
30 Accumulated Miscellaneous Operating
Provisions (228.4)0
31 Accumulated Provision for Rate Refunds (229)187,716,141 169,094,604
32 Long-Term Portion of Derivative Instrument
Liabilities 3,757,551
33 Long-Term Portion of Derivative Instrument
Liabilities - Hedges
34 Asset Retirement Obligations (230)36,697,825 27,691,367
35 Total Other Noncurrent Liabilities (lines 26
through 34)753,716,655 833,542,847
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)0
38 Accounts Payable (232)170,836,741 143,690,430
39 Notes Payable to Associated Companies (233)0
40 Accounts Payable to Associated Companies
(234)2,158,568 1,720,105
41 Customer Deposits (235)891,328 1,206,944
42 Taxes Accrued (236)262 (1,558,227)14,568,240
43 Interest Accrued (237)24,259,107 24,229,679
44 Dividends Declared (238)0
45 Matured Long-Term Debt (239)
46 Matured Interest (240)
47 Tax Collections Payable (241)1,478,743 1,401,632
48 Miscellaneous Current and Accrued Liabilities
(242)88,755,058 72,126,390
49 Obligations Under Capital Leases-Current (243)
50 Derivative Instrument Liabilities (244)5,747,262 143,733
51 (Less) Long-Term Portion of Derivative
Instrument Liabilities 3,757,551
52 Derivative Instrument Liabilities - Hedges (245)0
53 (Less) Long-Term Portion of Derivative
Instrument Liabilities-Hedges
54 Total Current and Accrued Liabilities (lines 37
through 53)288,811,029 259,087,153
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
FERC FORM No. 1 (REV. 12-03)
Page 112-113
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)8,350,901 5,709,312
57 Accumulated Deferred Investment Tax Credits
(255)266 109,459,666 97,626,769
58 Deferred Gains from Disposition of Utility Plant
(256)
59 Other Deferred Credits (253)269 9,055,170 9,649,332
60 Other Regulatory Liabilities (254)278 311,088,834 319,779,040
61 Unamortized Gain on Reaquired Debt (257)0
62 Accum. Deferred Income Taxes-Accel. Amort.
(281)272
63 Accum. Deferred Income Taxes-Other Property
(282)993,806,435 970,611,662
64 Accum. Deferred Income Taxes-Other (283)187,701,809 209,255,425
65 Total Deferred Credits (lines 56 through 64)1,619,462,815 1,612,631,540
66 TOTAL LIABILITIES AND STOCKHOLDER
EQUITY (lines 16, 24, 35, 54 and 65)7,142,274,134 7,085,944,312
FERC FORM No. 1 (REV. 12-03)
Page 112-113
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
1
UTILITY
OPERATING
INCOME
2 Operating Revenues
(400)300 1,456,168,287 1,347,383,706 1,456,168,287 1,347,383,706
3 Operating Expenses
4 Operation Expenses
(401)320 850,660,604 771,917,303 850,660,604 771,917,303
5 Maintenance
Expenses (402)320 66,854,588 58,598,841 66,854,588 58,598,841
6 Depreciation
Expense (403)336 165,446,697 162,750,617 165,446,697 162,750,617
7
Depreciation
Expense for Asset
Retirement Costs
(403.1)
336 0 (431,877)0 (431,877)
8 Amort. & Depl. of
Utility Plant (404-405)336 8,739,017 7,981,848 8,739,017 7,981,848
9 Amort. of Utility Plant
Acq. Adj. (406)336 15,018 15,018 15,018 15,018
10
Amort. Property
Losses, Unrecov
Plant and Regulatory
Study Costs (407)
0 0
11 Amort. of Conversion
Expenses (407.2)0 0
12 Regulatory Debits
(407.3)9,284,794 8,811,905 9,284,794 8,811,905
13 (Less) Regulatory
Credits (407.4)3,067,653 3,815,566 3,067,653 3,815,566
14 Taxes Other Than
Income Taxes (408.1)262 30,947,260 33,047,693 30,947,260 33,047,693
15 Income Taxes -
Federal (409.1)262 35,047,688 26,204,174 35,047,688 26,204,174
16 Income Taxes - Other
(409.1)262 13,298,956 6,286,258 13,298,956 6,286,258
17 Provision for Deferred
Income Taxes (410.1)
234,
272 22,846,006 27,020,124 22,846,006 27,020,124
FERC FORM No. 1 (REV. 02-04)
Page 114-117
18
(Less) Provision for
Deferred Income
Taxes-Cr. (411.1)
234,
272 44,552,318 33,253,251 44,552,318 33,253,251
19 Investment Tax Credit
Adj. - Net (411.4)266 11,832,897 2,820,899 11,832,897 2,820,899
20
(Less) Gains from
Disp. of Utility Plant
(411.6)
0 0
21 Losses from Disp. of
Utility Plant (411.7)0 0
22
(Less) Gains from
Disposition of
Allowances (411.8)
258,569 269,354 258,569 269,354
23
Losses from
Disposition of
Allowances (411.9)
0 0
24 Accretion Expense
(411.10)56,783 176,633 56,783 176,633
25
TOTAL Utility
Operating Expenses
(Enter Total of lines 4
thru 24)
1,167,151,768 1,067,861,265 1,167,151,768 1,067,861,265
27
Net Util Oper Inc
(Enter Tot line 2 less
25)
289,016,519 279,522,441 289,016,519 279,522,441
28 Other Income and
Deductions
29 Other Income
30 Nonutilty Operating
Income
31
Revenues From
Merchandising,
Jobbing and Contract
Work (415)
3,961,448 4,409,044
32
(Less) Costs and Exp.
of Merchandising,
Job. & Contract Work
(416)
4,522,755 4,633,866
33
Revenues From
Nonutility Operations
(417)
18,346 20,293
34
(Less) Expenses of
Nonutility Operations
(417.1)
52,086 60,764
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
35 Nonoperating Rental
Income (418)3,613 (449)
36
Equity in Earnings of
Subsidiary
Companies (418.1)
119 8,991,348 8,402,214
37 Interest and Dividend
Income (419)7,129,761 9,877,262
38
Allowance for Other
Funds Used During
Construction (419.1)
31,537,344 29,550,610
39
Miscellaneous
Nonoperating Income
(421)
(265,679)993,561
40 Gain on Disposition
of Property (421.1)7,217 8,399
41
TOTAL Other Income
(Enter Total of lines
31 thru 40)
46,808,557 48,566,304
42 Other Income
Deductions
43 Loss on Disposition
of Property (421.2)0 26,488
44 Miscellaneous
Amortization (425)
45 Donations (426.1)1,638,267 1,876,276
46 Life Insurance (426.2)(5,203,369)(4,035,855)
47 Penalties (426.3)1,002,943 16,172
48
Exp. for Certain Civic,
Political & Related
Activities (426.4)
1,031,900 911,610
49 Other Deductions
(426.5)8,871,633 8,737,704
50
TOTAL Other Income
Deductions (Total of
lines 43 thru 49)
7,341,374 7,532,395
51
Taxes Applic. to Other
Income and
Deductions
52 Taxes Other Than
Income Taxes (408.2)262 24,200 19,147
53 Income Taxes-
Federal (409.2)262 (644,711)406,255
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
54 Income Taxes-Other
(409.2)262 (196,593)122,919
55 Provision for Deferred
Inc. Taxes (410.2)
234,
272 103,913 111,185
56
(Less) Provision for
Deferred Income
Taxes-Cr. (411.2)
234,
272 692,073 726,433
57 Investment Tax Credit
Adj.-Net (411.5)0
58 (Less) Investment Tax
Credits (420)0
59
TOTAL Taxes on
Other Income and
Deductions (Total of
lines 52-58)
(1,405,264)(66,927)
60
Net Other Income and
Deductions (Total of
lines 41, 50, 59)
40,872,447 41,100,836
61 Interest Charges
62 Interest on Long-Term
Debt (427)84,144,940 84,250,809
63 Amort. of Debt Disc.
and Expense (428)1,338,232 1,433,636
64
Amortization of Loss
on Reaquired Debt
(428.1)
2,938,715 2,735,194
65
(Less) Amort. of
Premium on Debt-
Credit (429)
1,106,961 823,920
66
(Less) Amortization of
Gain on Reaquired
Debt-Credit (429.1)
0
67
Interest on Debt to
Assoc. Companies
(430)
0
68 Other Interest
Expense (431)11,341,371 11,370,843
69
(Less) Allowance for
Borrowed Funds
Used During
Construction-Cr. (432)
11,992,630 11,577,828
70
Net Interest Charges
(Total of lines 62 thru
69)
86,663,667 87,388,734
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
71
Income Before
Extraordinary Items
(Total of lines 27, 60
and 70)
243,225,299 233,234,543
72 Extraordinary Items
73 Extraordinary Income
(434)
74 (Less) Extraordinary
Deductions (435)
75
Net Extraordinary
Items (Total of line 73
less line 74)
0
76
Income Taxes-
Federal and Other
(409.3)
262
77
Extraordinary Items
After Taxes (line 75
less line 76)
0
78 Net Income (Total of
line 71 and 77)243,225,299 233,234,543
FERC FORM No. 1 (REV. 02-04)
Page 114-117
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
STATEMENT OF INCOME
Line
No.
Gas Utiity Current Year to Date
(in dollars)
(i)
Gas Utility Previous Year to
Date (in dollars)
(j)
Other Utility Current Year to
Date (in dollars)
(k)
Other Utility Previous Year to
Date (in dollars)
(l)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25 0 0
27 0 0
28
29
30
31
32
33
FERC FORM No. 1 (REV. 02-04)
Page 114-117
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
STATEMENT OF INCOME
Line
No.
Gas Utiity Current Year to Date
(in dollars)
(i)
Gas Utility Previous Year to
Date (in dollars)
(j)
Other Utility Current Year to
Date (in dollars)
(k)
Other Utility Previous Year to
Date (in dollars)
(l)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
66
67
68
69
70
71
72
73
74
75
76
77
78
FERC FORM No. 1 (REV. 02-04)
Page 114-117
STATEMENT OF INCOME
Line
No.
Gas Utiity Current Year to Date
(in dollars)
(i)
Gas Utility Previous Year to
Date (in dollars)
(j)
Other Utility Current Year to
Date (in dollars)
(k)
Other Utility Previous Year to
Date (in dollars)
(l)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
STATEMENT OF RETAINED EARNINGS
Line No.Item
(a)
Contra Primary
Account Affected
(b)
Current Quarter/Year Year to
Date Balance
(c)
Previous Quarter/Year Year
to Date Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS
(Account 216)
1 Balance-Beginning of Period 1,554,426,452 1,467,478,759
2 Changes
3 Adjustments to Retained Earnings (Account
439)
4 Adjustments to Retained Earnings Credit
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
9 TOTAL Credits to Retained Earnings (Acct. 439)
10 Adjustments to Retained Earnings Debit
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
15 TOTAL Debits to Retained Earnings (Acct. 439)
FERC FORM No. 1 (REV. 02-04)
Page 118-119
16 Balance Transferred from Income (Account 433
less Account 418.1)234,233,952 224,832,329
17 Appropriations of Retained Earnings (Acct. 436)
17.1
17.2
17.3
17.4
22 TOTAL Appropriations of Retained Earnings
(Acct. 436)
23 Dividends Declared-Preferred Stock (Account
437)
23.1
23.2
23.3
23.4
23.5
29 TOTAL Dividends Declared-Preferred Stock
(Acct. 437)
30 Dividends Declared-Common Stock (Account
438)
30.1 Acct 438
TOTAL
Dividends
Declared-
Common Stock
(146,075,623)(137,884,636)
30.2
30.3
30.4
30.5
36 TOTAL Dividends Declared-Common Stock
(Acct. 438)(146,075,623)(137,884,636)
37 Transfers from Acct 216.1, Unapprop. Undistrib.
Subsidiary Earnings 15,000,000
38 Balance - End of Period (Total
1,9,15,16,22,29,36,37)1,657,584,781 1,554,426,452
39 APPROPRIATED RETAINED EARNINGS
(Account 215)
39.1
39.2
STATEMENT OF RETAINED EARNINGS
Line No.Item
(a)
Contra Primary
Account Affected
(b)
Current Quarter/Year Year to
Date Balance
(c)
Previous Quarter/Year Year
to Date Balance
(d)
FERC FORM No. 1 (REV. 02-04)
Page 118-119
39.3
39.4
39.5
39.6
45 TOTAL Appropriated Retained Earnings
(Account 215)
APPROP. RETAINED EARNINGS - AMORT.
Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort.
Reserve, Federal (Acct. 215.1)13,273,106 13,273,106
47 TOTAL Approp. Retained Earnings (Acct. 215,
215.1) (Total 45,46)13,273,106 13,273,106
48 TOTAL Retained Earnings (Acct. 215, 215.1,
216) (Total 38, 47) (216.1)1,670,857,887 1,567,699,558
UNAPPROPRIATED UNDISTRIBUTED
SUBSIDIARY EARNINGS (Account Report
only on an Annual Basis, no Quarterly)
49 Balance-Beginning of Year (Debit or Credit)31,455,036 23,052,822
50 Equity in Earnings for Year (Credit) (Account
418.1)8,991,348 8,402,214
51 (Less) Dividends Received (Debit)15,000,000
52 TOTAL other Changes in unappropriated
undistributed subsidiary earnings for the year
52.1
53 Balance-End of Year (Total lines 49 thru 52)25,446,384 31,455,036
FERC FORM No. 1 (REV. 02-04)
Page 118-119
STATEMENT OF RETAINED EARNINGS
Line No.Item
(a)
Contra Primary
Account Affected
(b)
Current Quarter/Year Year to
Date Balance
(c)
Previous Quarter/Year Year
to Date Balance
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
STATEMENT OF CASH FLOWS
Line No.
Description (See Instructions No.1 for explanation of
codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities
2 Net Income (Line 78(c) on page 117)243,225,299 233,234,543
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 165,446,697 (e)162,318,740
5 Amortization of (Specify) (footnote details)
5.1 Plant 8,754,035
5.2 Unamortized debt expense 4,365,718
5.3 Unamortized discount (866,599)
5.4 Water Rights 1,042,009
5.5 Amortization of (a)(b)13,015,188
5.6 Other 104,721
8 Deferred Income Taxes (Net)(7,045,057)2,469,437
9 Investment Tax Credit Adjustment (Net)4,101,519 977,780
10 Net (Increase) Decrease in Receivables (6,292,909)(f)1,633,004
11 Net (Increase) Decrease in Inventory 990,657 (g)17,542,513
12 Net (Increase) Decrease in Allowances Inventory 0
13 Net Increase (Decrease) in Payables and Accrued
Expenses
(c)2,003,163 (h)11,828,778
14 Net (Increase) Decrease in Other Regulatory Assets (50,932,965)(i)(54,530,690)
15 Net Increase (Decrease) in Other Regulatory Liabilities 17,228,109 18,284,774
16 (Less) Allowance for Other Funds Used During
Construction 31,537,344 29,550,610
17 (Less) Undistributed Earnings from Subsidiary
Companies (9,927,830)(1,531,052)
18 Other (provide details in footnote):
18.1 Pension and postretirement benefit plan expense 33,803,097
18.2 Contributions to pension and postretirement benefit plans (44,206,756)
18.3 Changes in unbilled revenues (2,737,386)
18.4 Changes in prepayments (6,588,935)
18.5 Changes in company owned life insurance (4,961,062)
18.6 Other 1,321,971
FERC FORM No. 1 (ED. 12-96)
Page 120-121
18.7 Other (provide details in footnote):(j)(24,694,403)
22
Net Cash Provided by (Used in) Operating Activities
(Total of Lines 2 thru 21)337,145,812 354,060,106
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)(d)(331,509,226)(k)(l)(340,487,802)
27 Gross Additions to Nuclear Fuel 0
28 Gross Additions to Common Utility Plant 0
29 Gross Additions to Nonutility Plant 0
30 (Less) Allowance for Other Funds Used During
Construction (31,537,344)(m)(29,550,610)
31 Other (provide details in footnote):
31.1 Payments received from joint funding partners 5,876,358 0
31.2 Sale of renewable energy certificates and emission
allowances 2,230,655 0
31.3 Other (provide details in footnote):0 (n)(o)6,815,901
34 Cash Outflows for Plant (Total of lines 26 thru 33)(291,864,869)(p)(304,121,291)
36 Acquisition of Other Noncurrent Assets (d)0
37 Proceeds from Disposal of Noncurrent Assets (d)0
39 Investments in and Advances to Assoc. and Subsidiary
Companies 0 (q)(81,730)
40 Contributions and Advances from Assoc. and Subsidiary
Companies 0
41 Disposition of Investments in (and Advances to)
42 Disposition of Investments in (and Advances to)
Associated and Subsidiary Companies 0
44 Purchase of Investment Securities (a)(16,123,299)(r)(33,381,754)
45 Proceeds from Sales of Investment Securities (a)11,327,616 25,794,940
46 Loans Made or Purchased 0
47 Collections on Loans 0
49 Net (Increase) Decrease in Receivables 0
50 Net (Increase) Decrease in Inventory 0
51 Net (Increase) Decrease in Allowances Held for
Speculation 0
52 Net Increase (Decrease) in Payables and Accrued
Expenses 0
STATEMENT OF CASH FLOWS
Line No.
Description (See Instructions No.1 for explanation of
codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
FERC FORM No. 1 (ED. 12-96)
Page 120-121
53 Other (provide details in footnote):
53.1 Other (provide details in footnote):(s)2,768,025
57 Net Cash Provided by (Used in) Investing Activities (Total
of lines 34 thru 55)(296,660,552)(309,021,810)
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)0 341,384,461
62 Preferred Stock 0
63 Common Stock 0
64 Other (provide details in footnote):
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
70 Cash Provided by Outside Sources (Total 61 thru 69)0 341,384,461
72 Payments for Retirement of:
73 Long-term Debt (b)0 (t)(175,000,000)
74 Preferred Stock 0
75 Common Stock 0
76 Other (provide details in footnote):
76.1 Other (238,230)0
76.2 Other (provide details in footnote):0 (u)(v)(6,884,501)
78 Net Decrease in Short-Term Debt (c)0
80 Dividends on Preferred Stock 0
81 Dividends on Common Stock (146,075,623)(w)(137,884,636)
83 Net Cash Provided by (Used in) Financing Activities
(Total of lines 70 thru 81)(146,313,853)21,615,324
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 Net Increase (Decrease) in Cash and Cash Equivalents
(Total of line 22, 57 and 83)(105,828,593)66,653,620
88 Cash and Cash Equivalents at Beginning of Period 165,603,824 98,950,204
90 Cash and Cash Equivalents at End of Period 59,775,231 165,603,824
FERC FORM No. 1 (ED. 12-96)
Page 120-121
STATEMENT OF CASH FLOWS
Line No.
Description (See Instructions No.1 for explanation of
codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities
(b) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization
Year Ended
12/31/2021
Plant 8,754,035
Unamortized debt expense 4,365,718
Unamortized discount (866,599)
Water rights 1,042,009
Other 104,721
13,399,884
(c) Concept: NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Cash (received) paid during the period for:
Income taxes 58,279,359
Interest (net of amount capitalized)83,464,253
(d) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Non-cash investing activities:
Additions to PP&E in accounts payable 53,689,935
(e) Concept: DepreciationAndDepletion
(f) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 1633004
(g) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: 17542513
(h) Concept: NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
(i) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -54530690
(j) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities
(k) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
(l) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -340487802
(m) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -29550610
(n) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities
(o) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Original value: 6815901
(p) Concept: CashOutflowsForPlant
Original value: -304121291
(q) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -81730
(r) Concept: PurchaseOfInvestmentSecurities
Original value: -33381754
(s) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities
(t) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -175000000
(u) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -6884501
(v) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other Financing Cash FlowsOther (6,556,501)Discount on debt issuance (328,000) (6,884,501)
(w) Concept: DividendsOnCommonStock
Original value: -137884636
FERC FORM No. 1 (ED. 12-96)
Page 120-121
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or
of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in
arrears on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as
plant adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may
be omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
IDAHO POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Idaho Power Company (Idaho Power) is the principal operating subsidiary of IDACORP, Inc. (IDACORP), a holding company formed in 1998. Idaho Power is an electric utility
engaged in the generation, transmission, distribution, sales, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern
Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission
(FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger
generating plant (Jim Bridger plant) owned in part by Idaho Power.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses of Idaho Power and have been prepared in accordance with the accounting requirements of the FERC as
set forth in the applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally
accepted in the United States of America (U.S. GAAP). As required by the FERC, Idaho Power accounts for its investments in its majority-owned subsidiary on the equity method
rather than consolidating the assets, liabilities, revenues and expenses of the subsidiary as required by U.S GAAP. The accompanying financial statements include Idaho Power's
proportionate share of the utility plant and related operations resulting from its interest in jointly-owned plants. In addition, under the requirements of the FERC, there are differences
from U.S. GAAP in the presentation of (1) current portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assets and liabilities (4) deferred
income taxes, (5) income tax expense, (6) non-utility revenues, (7) accrued taxes, and (8) debt issue costs.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions include those related to rate
regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets
and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting
period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. Accordingly,
actual results could differ from those estimates.
Regulation of Utility Operations
As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized
to charge for its electric service. These approvals are a critical factor in determining Idaho Power's results of operations and financial condition.
Idaho Power meets the requirements under accounting principles generally accepted in the United States of America (GAAP) to prepare its financial statements applying the
specialized rules to account for the effects of cost-based rate regulation. Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the
jurisdictions regulating Idaho Power. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and
equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense. The application of accounting
principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record
such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent
incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to
customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's
operations are discussed in more detail in Note 3 - "Regulatory Matters."
System of Accounts
The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and
Wyoming.
Cash and Cash Equivalents
Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent per month may be assessed on account balances after 30 days.
An allowance is recorded for potential uncollectible accounts. The measurement of expected credit losses on Idaho Power accounts receivable is based on historical experience,
current economic conditions, and forecasted information that may affect collections on the outstanding balance. Generally, this includes adjustments based upon a combination of
historical write-off experience, aging of accounts receivable, an analysis of specific customer accounts, and an evaluation of whether there are current or forecasted economic
conditions that might cause variation in collection from the historical experience. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding
after reasonable collection efforts are written off.
In response to the COVID-19 public health crisis, Idaho Power provided certain relief to customers, including temporarily suspending disconnections for customers and temporarily
waiving late fees. This relief as well as the economic conditions created by the response to the COVID-19 public health crisis have resulted in higher aged accounts receivable and an
increase in the number of late payments. Compared with historical levels, Idaho Power expects higher uncollectible account write-offs as a result of the COVID-19 public health crisis
and, accordingly, has maintained its higher allowance for uncollectible accounts related to customer receivables at December 31, 2021.
The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of dollars):
Year Ended
December 31,
2021 2020
Balance at beginning of period $ 4,766 $ 1,401
Additions to the allowance 2,017 5,222
Write-offs, net of recoveries (2,284)(1,857)
Balance at end of period $ 4,499 $ 4,766
Allowance for uncollectible accounts as a percentage of customer receivables 5.4 %6.1 %
Other receivables are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that Idaho Power will be unable to collect all amounts due
according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income.
There were no impaired receivables without related allowances at December 31, 2021 and 2020. Once a receivable is determined to be impaired, any further interest income
recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All
derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the
exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power's
physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power's regulatory accounting mechanisms, Idaho Power records the unrealized
changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.
Revenues
Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered
to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In
addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail
in Note 4 - "Revenues."
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect
charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as
are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost
plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable
utility plant in service approximated 2.9 percent in 2021 and 2020.
During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are
classified as construction work in progress on the balance sheets. If the project becomes probable of being abandoned, these costs are expensed in the period such determination is
made. Idaho Power may seek recovery of these costs in customer rates, although there can be no guarantee such recovery would be granted.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of
the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no material
impairments of long-lived assets in 2021 and 2020.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, for the Hells Canyon Complex (HCC) relicensing project,
cash is not realized currently from such allowance; it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a
higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense. Idaho Power's
weighted-average monthly AFUDC rate was 7.5 percent for 2021 and 2020.
Income Taxes
Idaho Power accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax
consequences of events that have been included in the financial statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities are
determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are
expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred tax assets and liabilities from the beginning to the
end of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's
primary regulator, the Idaho Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income tax expense or benefit for certain
income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting.
Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in future rates.
Idaho Power uses judgment, estimation, and historical data in developing the provision for income taxes and the reporting of tax-related assets and liabilities, including development
of current year tax depreciation, capitalized repair costs, capitalized overheads, and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretations
by taxing authorities, changes to accounting guidance, and actions by federal or state public utility regulators. Actual income taxes could vary from estimated amounts and may result
in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.
In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power records deferred income taxes related to its plant assets for the
difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are recorded for other temporary differences unless
accounted for using flow-through.
Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties.
Income taxes are discussed in more detail in Note 2 - "Income Taxes."
Other Accounting Policies
Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issuances. Losses on reacquired debt and associated costs are amortized over the
life of the associated replacement debt, as allowed under regulatory accounting.
New and Recently Adopted Accounting Pronouncements
There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on Idaho Power's financial statements.
Subsequent Events
Management has evaluated the impact of events occurring after December 31, 2021, up to February 17, 2022, the date that Idaho Power Company's U.S. GAAP financial statements
were issued and has updated such evaluation for disclosure purposes through April 15, 2022. These financial statements include all necessary adjustments and disclosures resulting
from these evaluations.
2.INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
2021 2020
(thousands of dollars)
Federal income tax expense at 21% statutory rate $ 58,857 $ 55,068
Change in taxes resulting from:
Equity earnings of subsidiary companies (1,888)(1,764)
AFUDC (9,141)(8,637)
Capitalized interest 1,077 1,044
Investment tax credits (2,866)(2,906)
Bond redemption costs 0 (726)
Removal costs (3,302)(3,148)
Capitalized overhead costs (8,190)(7,560)
Capitalized repair costs (17,430)(18,480)
State income taxes, net of federal benefit 11,633 9,052
Depreciation 14,233 13,589
Excess deferred income tax reversal (8,958)(4,884)
Income tax return adjustments 2,690 (1,972)
Other, net 329 316
Total income tax expense $ 37,044 $ 28,992
Effective tax rate 13.2%11.1%
The items comprising income tax expense are as follows:2021 2020
(thousands of dollars)
Income taxes currently payable:
Federal $ 34,574 $ 26,610
State 12,932 6,409
Total 47,506 33,019
Income taxes deferred:
Federal (16,999)(2,607)
State (5,295)(4,241)
Total (22,294)(6,848)
Investment tax credits:
Deferred 14,698 5,727
Restored (2,866)(2,906)
Total 11,832 2,821
Total income tax expense $ 37,044 $ 28,992
The components of the net deferred tax liability are as follows:2021 2020
(thousands of dollars)
Deferred tax assets:
Regulatory liabilities $ 96,880 $ 95,883
Deferred compensation 23,333 22,576
Deferred revenue 48,318 43,525
Tax credits 35,781 30,215
Retirement benefits 110,997 142,864
Other 9,379 8,447
Total 324,688 343,510
Deferred tax liabilities:
Property, plant and equipment 272,530 282,983
Regulatory assets 721,276 687,628
Retirement benefits 138,154 164,399
Other 49,548 44,857
Total 1,181,508 1,179,867
Net deferred tax liabilities $ 856,820 $ 836,357
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are
settled through IDACORP and are reported as taxes accrued or income taxes receivable, respectively, on the balance sheets of Idaho Power. See Note 1 - "Summary of Significant
Accounting Policies" for further discussion of accounting policies related to income taxes.
Uncertain Tax Positions
Idaho Power believes that it has no material income tax uncertainties for 2021 and prior tax years. Idaho Power recognizes interest accrued related to unrecognized tax benefits as
interest expense and penalties as other expense.
Idaho Power is subject to examination by their major tax jurisdictions - United States federal and the State of Idaho. The open tax years for examination are 2020-2021 for federal and
2016-2021 for Idaho. The Idaho State Tax Commission began its examination of the 2016-2018 tax years in March of 2020. In May 2009, IDACORP formally entered the U.S. Internal
Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program provides
for IRS examination and issue resolution throughout the current year with the objective of return filings containing no contested items. The IRS moved IDACORP from the
maintenance phase of CAP to the bridge phase for both the 2020 and 2021 tax years.
Excess Deferred Income Taxes
Following the enactment of income tax reform in 2017, Idaho Power was required to remeasure its deferred tax assets and liabilities at the new federal corporate income tax rate which
resulted in lower net deferred tax liabilities and the establishment of a net regulatory liability for its depreciation-related excess deferred income taxes (EDIT). Idaho Power's deferred
taxes for depreciation-related temporary differences on its public utility property are subject to the normalization method of accounting. As provided in the 2017 income tax reform
statute, the normalization method requires the use of either the average rate assumption method (ARAM) or the alternative method for the reversal of the EDIT. In 2021, Idaho Power
began using the alternative method for the EDIT reversal pursuant to the interpretation of an Internal Revenue Service revenue procedure and series of related private letter rulings.
The alternative method results in the ratable return of the EDIT to customers over the remaining regulatory lives of Idaho Power's plant assets. For fiscal years 2018-2020, the ARAM
method was used to reverse the EDIT.
3. REGULATORY MATTERS
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho
Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.
Regulatory Assets and Liabilities
The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an
unregulated enterprise would record those expenses and revenues. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from
customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of
incurring an expense.
The following table presents a summary of Idaho Power's regulatory assets and liabilities (in thousands of dollars):
As of December 31, 2021
Remaining
Amortization
Period
Earning a
Return(1)
Not Earning
a Return
Total as of December 31,
Description 2021 2020
Regulatory Assets:
Income taxes(2)$$ 721,276 $ 721,276 $ 687,628
Unfunded postretirement benefits(3)315,011 315,011 444,470
Pension expense deferrals(4)197,623 36,814 234,437 200,686
Energy efficiency program costs(5)7,622 7,622 13,225
Power supply costs(6)2022-2023 42,940 (9,317)33,623
Fixed cost adjustment(6)2022-2023 35,058 19,886 54,944 55,491
North Valmy plant settlements(6)2022-2028 97,852 97,852 103,085
Asset retirement obligations(7)22,585 22,585 19,035
Wildfire Mitigation Plan deferral(6)6,075 6,075
Long-term service agreement 2022-2043 14,046 9,227 23,273 24,431
Other 2022-2055 2,846 14,204 17,050 10,844
Total $ 397,987 $ 1,135,761 $ 1,533,748 $ 1,558,895
Regulatory Liabilities:
Income taxes(8)$$ 96,880 $ 96,880 $ 95,883
Depreciation-related excess deferred income
taxes(9)170,039 170,039 178,997
Power supply costs(6)15,009
Settlement agreement sharing mechanism(6)2022-2023 569 569
Mark-to-market liabilities 8,581 8,581 1,995
Tax reform accrual for future
amortization(10)24,522 24,522 16,893
Other 4,697 5,801 10,498 11,002
Total $ 175,305 $ 135,789 $ 311,089 $ 319,779
(1) Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.
(2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes."
(3) Represents the unfunded obligation of Idaho Power's pension and postretirement benefit plans, which are discussed in Note 11 - "Benefit Plans."
(4) Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan. In its
Idaho jurisdiction, Idaho Power's inclusion of pension costs for the establishment of retail rates is based upon contributions made to the pension plan. This regulatory asset account represents the difference
between cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the amounts are provided for in Idaho retail revenues.
(5) The energy efficiency asset includes both the Idaho and Oregon jurisdiction balances at December 31, 2021 and 2020.
(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations and removal costs are discussed in Note 13 - "Asset Retirement Obligations (ARO)."
(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 -
"Income Taxes."
(9) In 2017, income tax reform reduced deferred income tax assets and liabilities. For depreciation-related temporary differences under the normalized tax accounting method, the resulting excess deferred taxes
will flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the alternative method provided in the statute. The average rate assumption method was used to
compute this reversal for fiscal years 2018-2020.
compute this reversal for fiscal years 2018-2020.
(10) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement Stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that would
otherwise be a future liability recoverable from Idaho customers.
Idaho Power's regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power's costs
through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power's operations and the items above may represent stranded
investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the
rates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesale
energy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power
supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund. The power
supply costs deferred primarily result from changes in the levels of Idaho Power's own hydroelectric generation, changes in contracted power purchase prices and volumes, changes in
wholesale market prices and transaction volumes, and changes in fuel prices.
Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual power cost adjustment (PCA) consists of (a) a forecast component, based on a forecast of
net power supply costs in the coming year as compared with net power supply costs included in base rates; and (b) a true-up component, based on the difference between the previous
year's actual net power supply costs and the previous year's forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of
authorized true-up dollars matches the amounts authorized. The PCA mechanism also includes:
a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exceptions of
expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and
a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not distort the results of the mechanism.
The Idaho deferral period or Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the
subsequent June 1 through May 31 period. In May 2021, the IPUC ordered Idaho Power to initiate a case to review the PCA mechanism and propose any modifications it determines
are appropriate so the case may be processed before the filing of the 2022 PCA application in April 2022. In January 2022, the IPUC approved Idaho Power's proposed modifications
to the PCA, which simplify the mechanism without impairing the intent or effectiveness of the PCA and have no material impact on overall cost recovery.
The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:
Effective Date
$ Change
(millions)Notes
June 1, 2021 $ 39.1 The net increase in PCA revenues reflects a forecasted reduction in low-cost hydroelectric
generation as well as higher costs associated with forecasted PURPA power purchases. The
net increase in PCA revenues also reflects a smaller credit to customers thru the true-up
component.
June 1, 2020 $ 58.7 The $58.7 million increase in PCA rates reflects a return to a more normal level of power
supply costs as wholesale market energy prices came down from unusually high levels in
the previous year's PCA and a forecasted reduction in low-cost hydropower generation.
Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and a
power cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to
forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply
expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Oregon jurisdiction power supply cost changes
under the APCU and PCAM during each of 2021 and 2020 did not have a material impact on the companies' financial statements.
Notable Idaho Base Rate Adjustments
Idaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and 2019.
January 2012 and June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement
stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a
4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, in
connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction
base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base rates
specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.
The IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and in
the determination of the PCA rate that became effective June 1, 2014.
October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a
December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45
million of additional accumulated deferred investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized (October 2014 Idaho Earnings Support and
Sharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in the table below.
May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal
income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into
law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.
In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018,
the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified
items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers. The May
2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications noted in the table below, of the October 2014 Idaho Earnings Support
and Sharing Settlement Stipulation beyond its termination date of December 31, 2019.
The table below summarizes and compares the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation with the terms in the May 2018 Idaho Tax
Reform Settlement Stipulation that became applicable on January 1, 2020.
October 2014 Idaho Earnings Support and Sharing
Settlement Stipulation
(Effective through December 31, 2019)
May 2018 Idaho Tax Reform Settlement Stipulation
(Effective January 1, 2020, with no defined end date)
If Idaho Power's actual annual Idaho ROE in any year is less
than 9.5 percent, then Idaho Power may record additional
ADITC amortization up to $25 million to help achieve a 9.5
percent Idaho ROE for that year, and may record additional
ADITC amortization up to a total of $45 million over the
2015 through 2019 period. If the $45 million of ADITC are
completely amortized, the revenue sharing provisions below
would no longer be applicable.
If Idaho Power's actual annual Idaho ROE in any year is less
than 9.4 percent, then Idaho Power may amortize up to $25
million of additional ADITC to help achieve a 9.4 percent
Idaho ROE for that year, so long as the cumulative amount of
ADITC used does not exceed $45 million (Idaho Power will
have available and may continue to use any unused portion
of the $45 million of additional ADITC from the October
2014 Idaho Earnings Support and Sharing Settlement
Stipulation); however, Idaho Power may seek approval from
the IPUC to replenish the total amount of ADITC it is
permitted to amortize. If there are no remaining amounts of
ADITC authorized to be amortized, the revenue sharing
provisions below would not be applicable until ADITC is
compute this reversal for fiscal years 2018-2020.(10) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement Stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that wouldotherwise be a future liability recoverable from Idaho customers.Idaho Power's regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power's coststhrough rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power's operations and the items above may represent strandedinvestments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.Power Cost Adjustment Mechanisms and Deferred Power Supply CostsIn both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to therates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesaleenergy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net powersupply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund. The powersupply costs deferred primarily result from changes in the levels of Idaho Power's own hydroelectric generation, changes in contracted power purchase prices and volumes, changes inwholesale market prices and transaction volumes, and changes in fuel prices.Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual power cost adjustment (PCA) consists of (a) a forecast component, based on a forecast ofnet power supply costs in the coming year as compared with net power supply costs included in base rates; and (b) a true-up component, based on the difference between the previousyear's actual net power supply costs and the previous year's forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund ofauthorized true-up dollars matches the amounts authorized. The PCA mechanism also includes:a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exceptions ofexpenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; anda sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not distort the results of the mechanism.The Idaho deferral period or Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during thesubsequent June 1 through May 31 period. In May 2021, the IPUC ordered Idaho Power to initiate a case to review the PCA mechanism and propose any modifications it determinesare appropriate so the case may be processed before the filing of the 2022 PCA application in April 2022. In January 2022, the IPUC approved Idaho Power's proposed modificationsto the PCA, which simplify the mechanism without impairing the intent or effectiveness of the PCA and have no material impact on overall cost recovery.The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:Effective Date $ Change(millions)NotesJune 1, 2021 $ 39.1 The net increase in PCA revenues reflects a forecasted reduction in low-cost hydroelectricgeneration as well as higher costs associated with forecasted PURPA power purchases. Thenet increase in PCA revenues also reflects a smaller credit to customers thru the true-upcomponent.June 1, 2020 $ 58.7 The $58.7 million increase in PCA rates reflects a return to a more normal level of powersupply costs as wholesale market energy prices came down from unusually high levels inthe previous year's PCA and a forecasted reduction in low-cost hydropower generation.Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and apower cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and toforecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supplyexpenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Oregon jurisdiction power supply cost changesunder the APCU and PCAM during each of 2021 and 2020 did not have a material impact on the companies' financial statements.Notable Idaho Base Rate AdjustmentsIdaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and 2019.January 2012 and June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlementstipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, inconnection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdictionbase rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base ratesspecified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.The IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and inthe determination of the PCA rate that became effective June 1, 2014.October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of aDecember 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45million of additional accumulated deferred investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized (October 2014 Idaho Earnings Support andSharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in the table below.May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federalincome tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed intolaw reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018,the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specifieditems or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers. The May2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications noted in the table below, of the October 2014 Idaho Earnings Supportand Sharing Settlement Stipulation beyond its termination date of December 31, 2019.The table below summarizes and compares the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation with the terms in the May 2018 Idaho TaxReform Settlement Stipulation that became applicable on January 1, 2020.October 2014 Idaho Earnings Support and SharingSettlement Stipulation(Effective through December 31, 2019)May 2018 Idaho Tax Reform Settlement Stipulation(Effective January 1, 2020, with no defined end date)If Idaho Power's actual annual Idaho ROE in any year is lessthan 9.5 percent, then Idaho Power may record additionalADITC amortization up to $25 million to help achieve a 9.5percent Idaho ROE for that year, and may record additionalADITC amortization up to a total of $45 million over the2015 through 2019 period. If the $45 million of ADITC arecompletely amortized, the revenue sharing provisions belowwould no longer be applicable.If Idaho Power's actual annual Idaho ROE in any year is lessthan 9.4 percent, then Idaho Power may amortize up to $25million of additional ADITC to help achieve a 9.4 percentIdaho ROE for that year, so long as the cumulative amount ofADITC used does not exceed $45 million (Idaho Power willhave available and may continue to use any unused portionof the $45 million of additional ADITC from the October2014 Idaho Earnings Support and Sharing SettlementStipulation); however, Idaho Power may seek approval fromthe IPUC to replenish the total amount of ADITC it ispermitted to amortize. If there are no remaining amounts of
ADITC authorized to be amortized, the revenue sharing
provisions below would not be applicable until ADITC isprovisions below would not be applicable until ADITC is
replenished.
If Idaho Power's annual Idaho ROE in any year exceeds 10.0
percent, the amount of earnings exceeding a 10.0 percent
Idaho ROE and up to and including a 10.5 percent Idaho
ROE will be allocated 75 percent to Idaho Power's Idaho
customers as a rate reduction to be effective at the time of the
subsequent year's PCA, and 25 percent to Idaho Power.
If Idaho Power's annual Idaho ROE in any year exceeds 10.0
percent, the amount of earnings exceeding a 10.0 percent
Idaho ROE and up to and including a 10.5 percent Idaho ROE
will be allocated 80 percent to Idaho Power's Idaho customers
as a rate reduction to be effective at the time of the
subsequent year's PCA, and 20 percent to Idaho Power.
If Idaho Power's annual Idaho ROE in any year exceeds 10.5
percent, the amount of earnings exceeding a 10.5 percent
Idaho ROE will be allocated 50 percent to Idaho Power's
Idaho customers as a rate reduction to be effective at the time
of the subsequent year's PCA, 25 percent to Idaho Power's
Idaho customers in the form of a reduction to the pension
regulatory asset balancing account (to reduce the amount to
be collected in the future from Idaho customers), and 25
percent to Idaho Power.
If Idaho Power's annual Idaho ROE in any year exceeds 10.5
percent, the amount of earnings exceeding a 10.5 percent
Idaho ROE will be allocated 55 percent to Idaho Power's
Idaho customers as a rate reduction to be effective at the time
of the subsequent year's PCA, 25 percent to Idaho Power's
Idaho customers in the form of a reduction to the pension
regulatory asset balancing account (to reduce the amount to
be collected in the future from Idaho customers), and 20
percent to Idaho Power.
In the event the IPUC approves a change to Idaho Power's
allowed annual Idaho ROE as part of a general rate case
proceeding before December 31, 2019, the Idaho ROE
thresholds will be adjusted on a prospective basis as follows:
(a) the Idaho ROE under which Idaho Power will be permitted
to amortize an additional amount of ADITC will be set at 95
percent of the newly authorized Idaho ROE, (b) sharing with
customers on an 75 percent basis as a customer rate reduction
will begin at the newly authorized Idaho ROE, and (c)
sharing with customers on a 75 percent basis but allocated 50
percent to a rate reduction, and 25 percent to a pension
expense deferral regulatory asset, will begin at 105 percent of
the newly authorized Idaho ROE.
In the event the IPUC approves a change to Idaho Power's
allowed annual Idaho ROE as part of a general rate case
proceeding effective on or after January 1, 2020, the Idaho
ROE thresholds will be adjusted on a prospective basis as
follows: (a) the Idaho ROE under which Idaho Power will be
permitted to amortize an additional amount of ADITC will be
set at 95 percent of the newly authorized Idaho ROE, (b)
sharing with customers on an 80 percent basis as a customer
rate reduction will begin at the newly authorized Idaho ROE,
and (c) sharing with customers on an 80 percent basis but
allocated 55 percent to a rate reduction, and 25 percent to a
pension expense deferral regulatory asset, will begin at 105
percent of the newly authorized Idaho ROE.
The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its
respective term.
In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho
ROE) exceeded 10.0 percent. In 2020, Idaho Power recorded no provision against current revenue for sharing with customers, as its Idaho ROE was between 9.4 percent and 10.0
percent in 2020. Accordingly, at December 31, 2021, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform
Settlement Stipulation.
Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power's
jointly-owned North Valmy coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized
collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent
and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 no later than the end of 2025. The costs intended to be recovered
by the increased jurisdictional revenues include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted
decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory accrual or
deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs
incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period
specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation,
collection or refund of any differences would be subject to regulatory approval. In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end
of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy coal-fired power plant in 2019 and no later than 2025, respectively. In May
2019, the IPUC issued an order approving the North Valmy plant agreement and allowing Idaho Power to recover through customer rates the $1.2 million incremental annual levelized
revenue requirement associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned,
Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1. In September 2021, the IPUC issued an order acknowledging Idaho Power's year-end 2025
exit date from Valmy unit 2 is appropriate based on economics and reliability needs.
Other Notable Idaho Regulatory Matters
Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a
portion of Idaho Power's financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour (kWh)
charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kWh charge, which
may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows Idaho
Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the
year. The IPUC has discretion to cap the annual increase in the FCA recovery at 3 percent of base revenue, with any excess deferred for collection in a subsequent year. In May 2021,
the IPUC ordered Idaho Power to work with interested parties and initiate a case to review the FCA mechanism and propose modifications it determines are appropriate. In December
2021, the IPUC approved Idaho Power's proposed modifications to the FCA mechanism to institute separate, and reduced, fixed cost tracking for customers added to Idaho Power's
system after December 31, 2021.
The following table summarizes FCA amounts approved for collection in the prior three FCA years:
FCA Year Period Rates in Effect
Annual Amount
(in millions)
2020 June 1, 2021-May 31, 2022 $38.3
2019 June 1, 2020-May 31, 2021 $35.5
2018 June 1, 2019-May 31, 2020 $34.8
Wildfire Mitigation Cost Recovery: In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental operations and maintenance (O&M) and depreciation
expense for certain capital investments necessary to implement Idaho Power's Wildfire Mitigation Plan (WMP). The IPUC also authorized Idaho Power to record these deferred
expenses as a regulatory asset until Idaho Power can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review
actual costs and determine the amount of prudently incurred costs that Idaho Power can recover through retail rates. In the filing, Idaho Power projected spending approximately $47
million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening capital incremental expenditures over a five-year period.
The IPUC authorized a deferral period of five years, or until rates go into effect from Idaho Power's next general rate case, whichever is first. As of December 31, 2021, Idaho Power's
deferral related to the WMP was $6.1 million.
Jim Bridger Power Plant Rate Request: In June 2021, Idaho Power filed an application with the IPUC requesting authorization to (a) accelerate depreciation for the Jim Bridger plant,
to allow the plant to be fully depreciated and recovered by December 31, 2030, (b) establish a balancing account to track the incremental costs and benefits associated with ceasing
participation in coal-fired operations at the Jim Bridger plant, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement.
In September 2021, the co-owner and operator of the Jim Bridger Plant submitted its IRP to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 and
converting those units to natural gas generation by 2024. Idaho Power's 2021 IRP includes the same plan. At a public meeting in October 2021, the IPUC approved a joint motion by
Idaho Power and the IPUC Staff to suspend the procedural schedule in Idaho Power's rate request case to assess new developments that impact operations at the Jim Bridger plant,
citing the potential option to convert the two units to natural gas generation as well as ongoing regional haze compliance discussions. In February 2022, Idaho Power filed a request to
resume the procedural schedule with an amended application to the IPUC that contemplates the conversion of units 1 and 2 to natural gas in 2024 and therefore removes from the
application all investments for the portion of the plant that will be converted to support gas-fired operations, leaving just coal-related plant investments in the requested regulatory
treatment. The updated filing requests authorization to adjust customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of
$27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operations at the Jim Bridger plant. The proposed adjustment in this application
provisions below would not be applicable until ADITC isreplenished.If Idaho Power's annual Idaho ROE in any year exceeds 10.0percent, the amount of earnings exceeding a 10.0 percentIdaho ROE and up to and including a 10.5 percent IdahoROE will be allocated 75 percent to Idaho Power's Idahocustomers as a rate reduction to be effective at the time of thesubsequent year's PCA, and 25 percent to Idaho Power.If Idaho Power's annual Idaho ROE in any year exceeds 10.0percent, the amount of earnings exceeding a 10.0 percentIdaho ROE and up to and including a 10.5 percent Idaho ROEwill be allocated 80 percent to Idaho Power's Idaho customersas a rate reduction to be effective at the time of thesubsequent year's PCA, and 20 percent to Idaho Power.If Idaho Power's annual Idaho ROE in any year exceeds 10.5percent, the amount of earnings exceeding a 10.5 percentIdaho ROE will be allocated 50 percent to Idaho Power'sIdaho customers as a rate reduction to be effective at the timeof the subsequent year's PCA, 25 percent to Idaho Power'sIdaho customers in the form of a reduction to the pensionregulatory asset balancing account (to reduce the amount tobe collected in the future from Idaho customers), and 25percent to Idaho Power.If Idaho Power's annual Idaho ROE in any year exceeds 10.5percent, the amount of earnings exceeding a 10.5 percentIdaho ROE will be allocated 55 percent to Idaho Power'sIdaho customers as a rate reduction to be effective at the timeof the subsequent year's PCA, 25 percent to Idaho Power'sIdaho customers in the form of a reduction to the pensionregulatory asset balancing account (to reduce the amount tobe collected in the future from Idaho customers), and 20percent to Idaho Power.In the event the IPUC approves a change to Idaho Power'sallowed annual Idaho ROE as part of a general rate caseproceeding before December 31, 2019, the Idaho ROEthresholds will be adjusted on a prospective basis as follows:(a) the Idaho ROE under which Idaho Power will be permittedto amortize an additional amount of ADITC will be set at 95percent of the newly authorized Idaho ROE, (b) sharing withcustomers on an 75 percent basis as a customer rate reductionwill begin at the newly authorized Idaho ROE, and (c)sharing with customers on a 75 percent basis but allocated 50percent to a rate reduction, and 25 percent to a pensionexpense deferral regulatory asset, will begin at 105 percent ofthe newly authorized Idaho ROE.In the event the IPUC approves a change to Idaho Power'sallowed annual Idaho ROE as part of a general rate caseproceeding effective on or after January 1, 2020, the IdahoROE thresholds will be adjusted on a prospective basis asfollows: (a) the Idaho ROE under which Idaho Power will bepermitted to amortize an additional amount of ADITC will beset at 95 percent of the newly authorized Idaho ROE, (b)sharing with customers on an 80 percent basis as a customerrate reduction will begin at the newly authorized Idaho ROE,and (c) sharing with customers on an 80 percent basis butallocated 55 percent to a rate reduction, and 25 percent to apension expense deferral regulatory asset, will begin at 105percent of the newly authorized Idaho ROE.The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during itsrespective term.In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (IdahoROE) exceeded 10.0 percent. In 2020, Idaho Power recorded no provision against current revenue for sharing with customers, as its Idaho ROE was between 9.4 percent and 10.0percent in 2020. Accordingly, at December 31, 2021, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax ReformSettlement Stipulation.Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power'sjointly-owned North Valmy coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelizedcollections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudentand commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 no later than the end of 2025. The costs intended to be recoveredby the increased jurisdictional revenues include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasteddecommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory accrual ordeferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costsincurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery periodspecified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation,collection or refund of any differences would be subject to regulatory approval. In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned endof Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy coal-fired power plant in 2019 and no later than 2025, respectively. In May2019, the IPUC issued an order approving the North Valmy plant agreement and allowing Idaho Power to recover through customer rates the $1.2 million incremental annual levelizedrevenue requirement associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned,Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1. In September 2021, the IPUC issued an order acknowledging Idaho Power's year-end 2025exit date from Valmy unit 2 is appropriate based on economics and reliability needs.Other Notable Idaho Regulatory MattersFixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small commercial customers, is designed to remove aportion of Idaho Power's financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour (kWh)charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kWh charge, whichmay result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows IdahoPower to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during theyear. The IPUC has discretion to cap the annual increase in the FCA recovery at 3 percent of base revenue, with any excess deferred for collection in a subsequent year. In May 2021,the IPUC ordered Idaho Power to work with interested parties and initiate a case to review the FCA mechanism and propose modifications it determines are appropriate. In December2021, the IPUC approved Idaho Power's proposed modifications to the FCA mechanism to institute separate, and reduced, fixed cost tracking for customers added to Idaho Power'ssystem after December 31, 2021.The following table summarizes FCA amounts approved for collection in the prior three FCA years:FCA Year Period Rates in Effect Annual Amount(in millions)2020 June 1, 2021-May 31, 2022 $38.32019June 1, 2020-May 31, 2021 $35.52018June 1, 2019-May 31, 2020 $34.8Wildfire Mitigation Cost Recovery: In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental operations and maintenance (O&M) and depreciationexpense for certain capital investments necessary to implement Idaho Power's Wildfire Mitigation Plan (WMP). The IPUC also authorized Idaho Power to record these deferredexpenses as a regulatory asset until Idaho Power can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to reviewactual costs and determine the amount of prudently incurred costs that Idaho Power can recover through retail rates. In the filing, Idaho Power projected spending approximately $47million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening capital incremental expenditures over a five-year period.The IPUC authorized a deferral period of five years, or until rates go into effect from Idaho Power's next general rate case, whichever is first. As of December 31, 2021, Idaho Power'sdeferral related to the WMP was $6.1 million.Jim Bridger Power Plant Rate Request: In June 2021, Idaho Power filed an application with the IPUC requesting authorization to (a) accelerate depreciation for the Jim Bridger plant,to allow the plant to be fully depreciated and recovered by December 31, 2030, (b) establish a balancing account to track the incremental costs and benefits associated with ceasingparticipation in coal-fired operations at the Jim Bridger plant, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement.In September 2021, the co-owner and operator of the Jim Bridger Plant submitted its IRP to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 andconverting those units to natural gas generation by 2024. Idaho Power's 2021 IRP includes the same plan. At a public meeting in October 2021, the IPUC approved a joint motion byIdaho Power and the IPUC Staff to suspend the procedural schedule in Idaho Power's rate request case to assess new developments that impact operations at the Jim Bridger plant,citing the potential option to convert the two units to natural gas generation as well as ongoing regional haze compliance discussions. In February 2022, Idaho Power filed a request toresume the procedural schedule with an amended application to the IPUC that contemplates the conversion of units 1 and 2 to natural gas in 2024 and therefore removes from the
application all investments for the portion of the plant that will be converted to support gas-fired operations, leaving just coal-related plant investments in the requested regulatory
treatment. The updated filing requests authorization to adjust customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of
$27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operations at the Jim Bridger plant. The proposed adjustment in this application$27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operations at the Jim Bridger plant. The proposed adjustment in this application
would result in an overall rate increase of 2.12 percent in Idaho. As of the date of this report, the case remains pending at the IPUC.
Notable Oregon Regulatory Matters
Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the Public Utility Commission of Oregon (OPUC)
issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in
the Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approving
an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon
rate base. Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulch
power plant revenue requirement variances, effective November 1, 2020, through October 31, 2024.
In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018,
through May 31, 2020, related to income tax reform. In May 2020, the OPUC issued an order to approve the quantification of $1.5 million in annualized Oregon jurisdictional
benefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next general
rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.
In June 2017, the OPUC approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery
of incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provides for an increase
in the Oregon jurisdictional revenue requirement of $1.1 million, with yearly adjustments, if warranted. In May 2018, the OPUC also deemed prudent Idaho Power's decision to pursue
the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to
unit 1, ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant agreement and authorized
Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the
decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.
Other Notable Regulatory Matters
Depreciation Rate Requests: In 2021, Idaho Power conducted a depreciation study of electric plant-in-service, which it performs approximately every five years. The study provided
updates to net salvage percentages and service life estimates for Idaho Power plant assets. In November 2021, in each of the Idaho and Oregon jurisdictions, Idaho Power and other
stakeholders filed a joint motion for approval of a settlement stipulation adopting new depreciation rates and agreeing to no increase in the jurisdictional revenue requirement and no
change in customer rates. In December 2021 and January 2022, respectively, the IPUC and OPUC approved Idaho Power's requests, which were effective January 1, 2022.
Federal Regulatory Matters - Open Access Transmission Tariff Rates
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and
operational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system. Idaho Power's OATT rates submitted to the FERC in
Idaho Power's three most recent annual OATT Final Informational Filings were as follows:
Applicable Period
OATT Rate (per
kW-year)
October 1, 2021 to September 30, 2022 $ 31.19
October 1, 2020 to September 30, 2021 $ 29.95
October 1, 2019 to September 30, 2020 $ 27.32
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $127.3 million, which represents the OATT formulaic determination of Idaho Power's net
cost of providing OATT-based transmission service.
4. REVENUES
Revenues from Contracts with Customers
Revenues from contracts with customers are primarily related to Idaho Power's regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a
written contract, but are classified as revenues from contracts with customers. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing,
and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands):
Retail Revenues: Idaho Power's retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in
amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed
component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the
consideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation.
Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power's
retail customer rates are based on Idaho Power's cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and
OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in
customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues
are not earned evenly during the year.
Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing.
Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end
and estimated rates.
Residential Customers: Idaho Power's energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increase
sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer
when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures
contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and
population growth in Idaho Power's service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives.
Idaho Power's FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives.
Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as are small industrial companies, and public street and highway lighting accounts.
Idaho Power's commercial customers are less influenced by weather conditions than residential customers, although weather does still affect commercial customer energy use.
Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. In 2021, a return to more normal
economic conditions for commercial customers compared with 2020 increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related business
conditions.
Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by
economic conditions, with weather having little impact on this customer class. In 2021, a return to more normal economic conditions for industrial customers compared with 2020
increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related business conditions.
Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well
as temperature levels affect the timing and amounts of sales to irrigation customers, with increased precipitation generally resulting in decreased sales.
Provision for Sharing: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-
jurisdictional earnings in excess of 10.0 percent of Idaho ROE. Based on full-year 2021 Idaho ROE, Idaho Power recorded $0.6 million provision against current revenues for sharing
of earnings with customers for 2021. During 2020, no provision against current revenues for sharing of earnings with customers was recorded. The regulatory settlement stipulations
are described further in Note 3 - "Regulatory Matters."
Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC
tariff. Idaho Power's wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied
as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve
$27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operations at the Jim Bridger plant. The proposed adjustment in this applicationwould result in an overall rate increase of 2.12 percent in Idaho. As of the date of this report, the case remains pending at the IPUC.Notable Oregon Regulatory MattersOregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the Public Utility Commission of Oregon (OPUC)issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent inthe Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approvingan approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregonrate base. Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulchpower plant revenue requirement variances, effective November 1, 2020, through October 31, 2024.In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018,through May 31, 2020, related to income tax reform. In May 2020, the OPUC issued an order to approve the quantification of $1.5 million in annualized Oregon jurisdictionalbenefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next generalrate case or other proceeding where the tax-related revenue requirement components are reflected in rates.In June 2017, the OPUC approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recoveryof incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provides for an increasein the Oregon jurisdictional revenue requirement of $1.1 million, with yearly adjustments, if warranted. In May 2018, the OPUC also deemed prudent Idaho Power's decision to pursuethe end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating tounit 1, ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant agreement and authorizedIdaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to thedecrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.Other Notable Regulatory MattersDepreciation Rate Requests: In 2021, Idaho Power conducted a depreciation study of electric plant-in-service, which it performs approximately every five years. The study providedupdates to net salvage percentages and service life estimates for Idaho Power plant assets. In November 2021, in each of the Idaho and Oregon jurisdictions, Idaho Power and otherstakeholders filed a joint motion for approval of a settlement stipulation adopting new depreciation rates and agreeing to no increase in the jurisdictional revenue requirement and nochange in customer rates. In December 2021 and January 2022, respectively, the IPUC and OPUC approved Idaho Power's requests, which were effective January 1, 2022.Federal Regulatory Matters - Open Access Transmission Tariff RatesIdaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial andoperational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system. Idaho Power's OATT rates submitted to the FERC inIdaho Power's three most recent annual OATT Final Informational Filings were as follows:Applicable Period OATT Rate (perkW-year)October 1, 2021 to September 30, 2022 $ 31.19October 1, 2020 to September 30, 2021 $ 29.95October 1, 2019 to September 30, 2020 $ 27.32Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $127.3 million, which represents the OATT formulaic determination of Idaho Power's netcost of providing OATT-based transmission service.4. REVENUESRevenues from Contracts with CustomersRevenues from contracts with customers are primarily related to Idaho Power's regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve awritten contract, but are classified as revenues from contracts with customers. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing,and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands):Retail Revenues: Idaho Power's retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues inamounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixedcomponent related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect theconsideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation.Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power'sretail customer rates are based on Idaho Power's cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC andOPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes incustomer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenuesare not earned evenly during the year.Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing.Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-endand estimated rates.Residential Customers: Idaho Power's energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increasesales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summerwhen overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structurescontribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth andpopulation growth in Idaho Power's service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives.Idaho Power's FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives.Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as are small industrial companies, and public street and highway lighting accounts.Idaho Power's commercial customers are less influenced by weather conditions than residential customers, although weather does still affect commercial customer energy use.Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. In 2021, a return to more normaleconomic conditions for commercial customers compared with 2020 increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related businessconditions.Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven byeconomic conditions, with weather having little impact on this customer class. In 2021, a return to more normal economic conditions for industrial customers compared with 2020increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related business conditions.Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as wellas temperature levels affect the timing and amounts of sales to irrigation customers, with increased precipitation generally resulting in decreased sales.Provision for Sharing: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE. Based on full-year 2021 Idaho ROE, Idaho Power recorded $0.6 million provision against current revenues for sharingof earnings with customers for 2021. During 2020, no provision against current revenues for sharing of earnings with customers was recorded. The regulatory settlement stipulationsare described further in Note 3 - "Regulatory Matters."
Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC
tariff. Idaho Power's wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied
as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serveas energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve
customer loads as well as adequate market power prices and demand at the time when those resources are available. A reduction in any of those factors may lead to lower wholesale
energy sales.
Transmission Wheeling-Related Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services
under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho
Power's transmission revenue is primarily related to third parties reserving capacity on Idaho Power's transmission system to transmit electricity through Idaho Power's service area.
Reservations are predominantly short-term contracts or on-demand when available, but may be part of a long-term capacity contract. Transmission wheeling-related revenues consist
of a single performance obligation satisfied as capacity on Idaho Power's transmission system is provided to the third party. Transmission wheeling-related revenues are affected by
changes in Idaho Power's OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in
Idaho Power's region.
Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are
deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recognized in
revenues, resulting in no net impact on earnings. Fewer energy efficiency projects were completed in 2021 due mostly to impacts of the COVID-19 public health crisis which
decreased energy efficiency program revenues compared with prior years. The cumulative variance between expenditures and amounts collected through the rider is recorded as a
regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it
has collected. At December 31, 2021, Idaho Power's energy efficiency rider balances were a $6.9 million regulatory asset in the Idaho jurisdiction and a $0.7 million regulatory asset in
the Oregon jurisdiction. In December 2020, the IPUC authorized Idaho Power to increase the Idaho energy efficiency rider collection percentage from 2.75 percent to 3.1 percent,
effective January 1, 2021.
Alternative Revenue Programs and Other Revenues
While revenues from contracts with customers make up most of Idaho Power's revenues, the IPUC has authorized the use of an additional regulatory mechanism, the Idaho FCA
mechanism, which may increase or decrease tariff-based customer rates. The Idaho FCA mechanism is described in Note 3 - "Regulatory Matters." The FCA mechanism revenues
include only the initial recognition of FCA revenues when they meet the regulator-specified conditions for recognition. Revenue from contracts with customers excludes the portion
of the tariff price representing FCA revenues that Idaho Power initially recorded in prior periods when revenues met regulator-specified conditions. When Idaho Power includes those
amounts in the price of utility service and billed to customers, Idaho Power records such amounts as recovery of the associated regulatory asset or liability and not as revenues.
Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits. Related to these
forward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on the
statements of income. For more information on settled electricity swaps, see Note 15 - "Derivative Financial Instruments."
5. LONG-TERM DEBT
The following table summarizes Idaho Power's long-term debt at December 31 (in thousands of dollars):
2021 2020
First mortgage bonds:
2.50% Series due 2023 $ 75,000 $ 75,000
1.90% Series due 2030 80,000 80,000
6.00% Series due 2032 100,000 100,000
5.50% Series due 2033 70,000 70,000
5.50% Series due 2034 50,000 50,000
5.875% Series due 2034 55,000 55,000
5.30% Series due 2035 60,000 60,000
6.30% Series due 2037 140,000 140,000
6.25% Series due 2037 100,000 100,000
4.85% Series due 2040 100,000 100,000
4.30% Series due 2042 75,000 75,000
4.00% Series due 2043 75,000 75,000
3.65% Series due 2045 250,000 250,000
4.05% Series due 2046 120,000 120,000
4.20% Series due 2048 450,000 450,000
Total first mortgage bonds 1,800,000 1,800,000
Pollution control revenue bonds:
1.45% Series due 2024(1)49,800 49,800
1.70% Series due 2026(1)116,300 116,300
Variable Rate Series 2000 due 2027 4,360 4,360
Total pollution control revenue bonds 170,460 170,460
American Falls bond guarantee 19,885 19,885
Unamortized premium/discount 25,637 26,503
Total Idaho Power outstanding debt(2)2,015,982 2,016,848
(1) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2021, to $1.966
billion.
(2) At both December 31, 2021 and 2020, the overall effective cost rate of Idaho Power's outstanding debt was 4.40 percent.
At December 31, 2021, the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
2022 2023 2024 2025 2026 Thereafter
$$ 75,000 $ 49,800 $ 19,885 $ 116,300 $ 1,729,360
Long-Term Debt Issuances, Maturities, and Redemptions
In April 2020, Idaho Power issued $230.0 million in principal amount of 4.20% first mortgage bonds, secured medium term notes, Series K, maturing March 1, 2048. The bonds were
issued at a reoffer yield of 3.422 percent, which resulted in a net premium of 13.0 percent and net proceeds to Idaho Power of $259.9 million. After this offering the aggregate principal
amount of the 4.20% first mortgage bonds is $450 million.
In June 2020, Idaho Power issued $80.0 million in principal amount of 1.90% first mortgage bonds, secured medium term notes, Series L, maturing July 15, 2030. In July 2020, Idaho
Power redeemed, prior to maturity, $75 million in principal amount of 2.95 percent first mortgage bonds, medium-term notes, Series H due in April 2022. In accordance with the
redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of $3.3
million.
In August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in November 2020.
as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to servecustomer loads as well as adequate market power prices and demand at the time when those resources are available. A reduction in any of those factors may lead to lower wholesaleenergy sales.Transmission Wheeling-Related Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission servicesunder its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. IdahoPower's transmission revenue is primarily related to third parties reserving capacity on Idaho Power's transmission system to transmit electricity through Idaho Power's service area.Reservations are predominantly short-term contracts or on-demand when available, but may be part of a long-term capacity contract. Transmission wheeling-related revenues consistof a single performance obligation satisfied as capacity on Idaho Power's transmission system is provided to the third party. Transmission wheeling-related revenues are affected bychanges in Idaho Power's OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities inIdaho Power's region.Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections aredeferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recognized inrevenues, resulting in no net impact on earnings. Fewer energy efficiency projects were completed in 2021 due mostly to impacts of the COVID-19 public health crisis whichdecreased energy efficiency program revenues compared with prior years. The cumulative variance between expenditures and amounts collected through the rider is recorded as aregulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than ithas collected. At December 31, 2021, Idaho Power's energy efficiency rider balances were a $6.9 million regulatory asset in the Idaho jurisdiction and a $0.7 million regulatory asset inthe Oregon jurisdiction. In December 2020, the IPUC authorized Idaho Power to increase the Idaho energy efficiency rider collection percentage from 2.75 percent to 3.1 percent,effective January 1, 2021.Alternative Revenue Programs and Other RevenuesWhile revenues from contracts with customers make up most of Idaho Power's revenues, the IPUC has authorized the use of an additional regulatory mechanism, the Idaho FCAmechanism, which may increase or decrease tariff-based customer rates. The Idaho FCA mechanism is described in Note 3 - "Regulatory Matters." The FCA mechanism revenuesinclude only the initial recognition of FCA revenues when they meet the regulator-specified conditions for recognition. Revenue from contracts with customers excludes the portionof the tariff price representing FCA revenues that Idaho Power initially recorded in prior periods when revenues met regulator-specified conditions. When Idaho Power includes thoseamounts in the price of utility service and billed to customers, Idaho Power records such amounts as recovery of the associated regulatory asset or liability and not as revenues.Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits. Related to theseforward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on thestatements of income. For more information on settled electricity swaps, see Note 15 - "Derivative Financial Instruments."5. LONG-TERM DEBTThe following table summarizes Idaho Power's long-term debt at December 31 (in thousands of dollars):2021 2020First mortgage bonds:2.50% Series due 2023 $ 75,000 $ 75,0001.90% Series due 2030 80,000 80,0006.00% Series due 2032 100,000 100,0005.50% Series due 2033 70,000 70,0005.50% Series due 2034 50,000 50,0005.875% Series due 2034 55,000 55,0005.30% Series due 2035 60,000 60,0006.30% Series due 2037 140,000 140,0006.25% Series due 2037 100,000 100,0004.85% Series due 2040 100,000 100,0004.30% Series due 2042 75,000 75,0004.00% Series due 2043 75,000 75,0003.65% Series due 2045 250,000 250,0004.05% Series due 2046 120,000 120,0004.20% Series due 2048 450,000 450,000Total first mortgage bonds 1,800,000 1,800,000Pollution control revenue bonds:1.45% Series due 2024(1)49,800 49,8001.70% Series due 2026(1)116,300 116,300Variable Rate Series 2000 due 2027 4,360 4,360Total pollution control revenue bonds 170,460 170,460American Falls bond guarantee 19,885 19,885Unamortized premium/discount 25,637 26,503Total Idaho Power outstanding debt(2)2,015,982 2,016,848(1) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2021, to $1.966billion.(2) At both December 31, 2021 and 2020, the overall effective cost rate of Idaho Power's outstanding debt was 4.40 percent.At December 31, 2021, the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in thousands of dollars):2022 2023 2024 2025 2026 Thereafter$$ 75,000 $ 49,800 $ 19,885 $ 116,300 $ 1,729,360Long-Term Debt Issuances, Maturities, and RedemptionsIn April 2020, Idaho Power issued $230.0 million in principal amount of 4.20% first mortgage bonds, secured medium term notes, Series K, maturing March 1, 2048. The bonds wereissued at a reoffer yield of 3.422 percent, which resulted in a net premium of 13.0 percent and net proceeds to Idaho Power of $259.9 million. After this offering the aggregate principalamount of the 4.20% first mortgage bonds is $450 million.In June 2020, Idaho Power issued $80.0 million in principal amount of 1.90% first mortgage bonds, secured medium term notes, Series L, maturing July 15, 2030. In July 2020, IdahoPower redeemed, prior to maturity, $75 million in principal amount of 2.95 percent first mortgage bonds, medium-term notes, Series H due in April 2022. In accordance with theredemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of $3.3
million.
In August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in November 2020.In August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in November 2020.
Idaho Power First Mortgage Bonds
Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2019, Idaho
Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt
securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2022, subject to extensions upon request to the
IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the
interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 7.0
percent.
In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first
mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and
Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of
covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.
In June 2020, Idaho Power entered into a selling agency agreement with six banks named in the agreement in
connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first
mortgage bonds, secured medium term notes, Series L (Series L Notes), under Idaho Power's Indenture of Mortgage and Deed
of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also in June 2020, Idaho Power
entered into the Forty-ninth Supplemental Indenture, dated effective as of June 5, 2020, to the Indenture (Forty-ninth
Supplemental Indenture). The Forty-ninth Supplemental Indenture provides for, among other items, the issuance of up to
$500 million in aggregate principal amount of Series L Notes pursuant to the Indenture.
The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future
will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including
liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts,
covenants, workmen's compensation awards, and similar encumbrances and minor defects common to properties. The mortgage of the Indenture does not create a lien on revenues or
profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise
or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted
property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or
appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these
expenditures or appropriations within the 5 years that immediately follow or precede a particular year.
The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the Indenture from $2.0 billion to $2.5 billion. Idaho
Power may amend the Indenture and increase this amount without consent of the holders of the first mortgage bonds. The amount issuable is also restricted by property, earnings, and
other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual interest
requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not
apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than 2 years or that are of an equal or higher interest rate, or prior lien bonds.
As of December 31, 2021, Idaho Power could issue under its Indenture approximately $2.1 billion of additional first mortgage bonds based on retired first mortgage bonds and total
unfunded property additions. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Forty-ninth Supplemental Indenture. As a result, the
maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2021, was limited to approximately $534 million under the Indenture.
6. NOTES PAYABLE
Credit Facilities
The Idaho Power credit facility, which may be used for general corporate purpose and commercial paper backup, consists of a revolving line of credit, through the issuance of loans
and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at
any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power has the right to
request an increase in the aggregate principal amount of the facilities to $450 million subject to certain conditions.
The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or
London interbank offered rate (LIBOR) Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal
funds rate and LIBOR rate will not be less than zero. The Secured Overnight Financing Rate (SOFR) plus a defined benchmark adjustment would replace the LIBOR Market Index rate
during any period in which the LIBOR rate is unavailable or unascertainable. If during any period both the LIBOR and SOFR rates are unavailable or unascertainable, an alternate
benchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on Idaho Power's senior unsecured long-term indebtedness credit
rating by rating agencies, as set forth on a schedule to the credit facility agreement. Under their respective credit facility, Idaho Power pays a facility fee on the commitment based on
the company's credit rating for senior unsecured long-term debt securities. In December 2021, Idaho Power amended its outstanding credit agreement to extend the termination date to
December 6, 2025, and provided additional information on potential alternatives, successors or replacement rates for LIBOR in the event it is no longer available as of the date of
borrowing, among other things. While the credit facility provides for an original maturity date of December 6, 2025, the credit agreement grants Idaho Power the right to request up to
two one-year extensions, subject to certain conditions.
At December 31, 2021, no loans were outstanding under Idaho Power's facility. At December 31, 2021, Idaho Power had regulatory authority to incur up to $450 million in principal
amount of short-term indebtedness at any one time outstanding through December of 2026. Idaho Power's short-term borrowings were zero at both December 31, 2021 and 2020.
7. COMMON STOCK
Idaho Power Common Stock
No contributions were made to Idaho Power in 2021 or 2020 and no additional shares of Idaho Power common stock were issued.
Restrictions on Dividends
Idaho Power's ability to pay dividends on its common stock held by IDACORP is limited to the extent payment of such dividends would violate the covenants in its credit facility or
Idaho Power's Revised Code of Conduct. A covenant under Idaho Power's credit facility requires Idaho Power to maintain a leverage ratio of consolidated indebtedness to consolidated
total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At December 31, 2021, the leverage ratio for Idaho Power was 45 percent. Based on
this restriction, Idaho Power's dividends were limited to $1.4 billion at December 31, 2021. There are additional facility covenants, subject to exceptions, that prohibit or restrict the
sale or disposition of property without consent and any agreements restricting dividend payments to Idaho Power from any material subsidiary. At December 31, 2021, Idaho Power
was in compliance with those covenants.
Idaho Power's Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April
2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital without
IPUC approval. At December 31, 2021, Idaho Power's common equity capital was 55 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUC
before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.
Idaho Power's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report,
Idaho Power has no preferred stock outstanding.
In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from "capital accounts." The term "capital account" is
undefined in the FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained
earnings.
In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $13.3 million of amortization reserves established for certain of its licensed hydroelectric facilities.
8. SHARE-BASED COMPENSATION
Through its parent company IDACORP, Idaho Power has one share-based compensation plan the 2000 Long-Term Incentive and Compensation Plan (LTICP). The LTICP (for officers,
key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units (together, Restricted Stock), performance shares and performance-based
units (together, Performance-Based Shares), and several other types of share-based awards. At December 31, 2021, the maximum number of shares available under the LTICP was
443,663.
Restricted Stock and Performance-Based Shares Awards
In August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in November 2020.Idaho Power First Mortgage BondsIdaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2019, IdahoPower received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debtsecurities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2022, subject to extensions upon request to theIPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that theinterest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 7.0percent.In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its firstmortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage andDeed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction ofcovenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.In June 2020, Idaho Power entered into a selling agency agreement with six banks named in the agreement inconnection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of firstmortgage bonds, secured medium term notes, Series L (Series L Notes), under Idaho Power's Indenture of Mortgage and Deedof Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also in June 2020, Idaho Powerentered into the Forty-ninth Supplemental Indenture, dated effective as of June 5, 2020, to the Indenture (Forty-ninthSupplemental Indenture). The Forty-ninth Supplemental Indenture provides for, among other items, the issuance of up to$500 million in aggregate principal amount of Series L Notes pursuant to the Indenture.The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the futurewill also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions includingliens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts,covenants, workmen's compensation awards, and similar encumbrances and minor defects common to properties. The mortgage of the Indenture does not create a lien on revenues orprofits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandiseor equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than exceptedproperty, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend orappropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up theseexpenditures or appropriations within the 5 years that immediately follow or precede a particular year.The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the Indenture from $2.0 billion to $2.5 billion. IdahoPower may amend the Indenture and increase this amount without consent of the holders of the first mortgage bonds. The amount issuable is also restricted by property, earnings, andother provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual interestrequirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does notapply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than 2 years or that are of an equal or higher interest rate, or prior lien bonds.As of December 31, 2021, Idaho Power could issue under its Indenture approximately $2.1 billion of additional first mortgage bonds based on retired first mortgage bonds and totalunfunded property additions. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Forty-ninth Supplemental Indenture. As a result, themaximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2021, was limited to approximately $534 million under the Indenture.6. NOTES PAYABLECredit FacilitiesThe Idaho Power credit facility, which may be used for general corporate purpose and commercial paper backup, consists of a revolving line of credit, through the issuance of loansand standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount atany time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power has the right torequest an increase in the aggregate principal amount of the facilities to $450 million subject to certain conditions.The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, orLondon interbank offered rate (LIBOR) Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federalfunds rate and LIBOR rate will not be less than zero. The Secured Overnight Financing Rate (SOFR) plus a defined benchmark adjustment would replace the LIBOR Market Index rateduring any period in which the LIBOR rate is unavailable or unascertainable. If during any period both the LIBOR and SOFR rates are unavailable or unascertainable, an alternatebenchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on Idaho Power's senior unsecured long-term indebtedness creditrating by rating agencies, as set forth on a schedule to the credit facility agreement. Under their respective credit facility, Idaho Power pays a facility fee on the commitment based onthe company's credit rating for senior unsecured long-term debt securities. In December 2021, Idaho Power amended its outstanding credit agreement to extend the termination date toDecember 6, 2025, and provided additional information on potential alternatives, successors or replacement rates for LIBOR in the event it is no longer available as of the date ofborrowing, among other things. While the credit facility provides for an original maturity date of December 6, 2025, the credit agreement grants Idaho Power the right to request up totwo one-year extensions, subject to certain conditions.At December 31, 2021, no loans were outstanding under Idaho Power's facility. At December 31, 2021, Idaho Power had regulatory authority to incur up to $450 million in principalamount of short-term indebtedness at any one time outstanding through December of 2026. Idaho Power's short-term borrowings were zero at both December 31, 2021 and 2020.7. COMMON STOCKIdaho Power Common StockNo contributions were made to Idaho Power in 2021 or 2020 and no additional shares of Idaho Power common stock were issued.Restrictions on DividendsIdaho Power's ability to pay dividends on its common stock held by IDACORP is limited to the extent payment of such dividends would violate the covenants in its credit facility orIdaho Power's Revised Code of Conduct. A covenant under Idaho Power's credit facility requires Idaho Power to maintain a leverage ratio of consolidated indebtedness to consolidatedtotal capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At December 31, 2021, the leverage ratio for Idaho Power was 45 percent. Based onthis restriction, Idaho Power's dividends were limited to $1.4 billion at December 31, 2021. There are additional facility covenants, subject to exceptions, that prohibit or restrict thesale or disposition of property without consent and any agreements restricting dividend payments to Idaho Power from any material subsidiary. At December 31, 2021, Idaho Powerwas in compliance with those covenants.Idaho Power's Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital withoutIPUC approval. At December 31, 2021, Idaho Power's common equity capital was 55 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUCbefore it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.Idaho Power's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report,Idaho Power has no preferred stock outstanding.In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from "capital accounts." The term "capital account" isundefined in the FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retainedearnings.In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $13.3 million of amortization reserves established for certain of its licensed hydroelectric facilities.8. SHARE-BASED COMPENSATIONThrough its parent company IDACORP, Idaho Power has one share-based compensation plan the 2000 Long-Term Incentive and Compensation Plan (LTICP). The LTICP (for officers,key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units (together, Restricted Stock), performance shares and performance-based
units (together, Performance-Based Shares), and several other types of share-based awards. At December 31, 2021, the maximum number of shares available under the LTICP was
443,663.
Restricted Stock and Performance-Based Shares AwardsRestricted Stock and Performance-Based Shares Awards
Restricted Stock awards have three-year vesting periods and entitle the recipients to dividends or dividend equivalents, as applicable, and voting rights, except that holders of
restricted stock units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition and subject to forfeiture under certain
circumstances. The fair value of these awards is based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period,
reduced for any forfeitures during the vesting period.
Performance-Based Shares awards have three-year vesting periods and entitle the recipients to voting rights, except that holders of performance-based units do not have voting rights
until the units are vested and settled in shares. Unvested awards are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to the attainment of
specific performance conditions over the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and total
shareholder return (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and the year issued, the final number of shares awarded can
range from zero to 200 percent of the target award. Dividends or dividend equivalents, as applicable, are accrued during the vesting period and paid out based on the final number of
shares awarded.
The grant-date fair value of the CEPS portion is based on the closing market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments.
The fair value of this portion of the awards is charged to compensation expense over the requisite service period based on the estimated achievement of performance targets, reduced
for any forfeitures during the vesting period. The grant-date fair value of the TSR portion is estimated using the market value at the date of grant and a statistical model that
incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The fair value of this portion of the awards is charged to
compensation expense over the requisite service period, provided the requisite service period is rendered, regardless of the level of TSR metric attained.
A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Idaho Power share amounts represent shares of IDACORP common stock:
Number of
Shares/Units
Weighted-
Average
Grant Date
Fair Value
Nonvested shares/units at January 1, 2021 156,013 $ 100.90
Shares/units granted 95,821 87.76
Shares/units forfeited (2,210)98.72
Shares/units vested (75,415)87.24
Nonvested shares/units at December 31, 2021 174,209 $ 99.61
The total fair value of shares vested was $6.7 million in 2021 and $10.5 million in 2020. At December 31, 2021, Idaho Power had $7.5 million of total unrecognized compensation
cost related to nonvested share-based compensation. These costs are expected to be recognized over a weighted-average period of 1.7 years. Original issue shares of IDACORP are used
for these awards.
In 2021, a total of 14,025 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at an average grant date fair value of $86.24 per share. Directors
elected to defer receipt of 2,550 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.
Compensation Expense: The following table shows Idaho Power's compensation cost recognized in income and the tax benefits resulting from the LTICP (in thousands of dollars):
2021 2020
Compensation cost $ 8,497 $ 7,339
Income tax benefit 2,187 1,889
No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the statements of income.
9. COMMITMENTS
Purchase Obligations
At December 31, 2021, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
2022 2023 2024 2025 2026 Thereafter
Cogeneration and power production $ 298,867 $ 308,741 $ 311,968 $ 296,579 $ 293,508 $ 2,456,582
Fuel 62,287 19,328 8,663 8,362 8,354 58,355
As of December 31, 2021, Idaho Power had 1,137 megawatt (MW) nameplate capacity of PURPA-related projects on-line, with an additional 75 MW nameplate capacity of projects
projected to be on-line by 2024. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with
PURPA-related projects were approximately $200 million in 2021 and $194 million in 2020. In February 2022, Idaho Power entered into a 20-year power purchase agreement with a
planned 40 MW solar facility expected to be in service in 2023 which increased Idaho Power's contractual purchase obligations by approximately $78 million over the term of the
contract.
Idaho Power also has the following long-term commitments (in thousands of dollars):
2022 2023 2024 2025 2026 Thereafter
Joint-operating agreement payments(1)$ 2,822 $ 2,822 $ 2,822 $ 2,822 $ 2,822 $ 14,110
Easements and other payments 1,925 1,965 2,006 2,049 2,092 11,136
Maintenance and service agreements(1)97,847 13,522 10,134 6,319 6,592 46,764
FERC and other industry-related fees(1)16,772 14,549 14,174 14,174 14,174 70,870
(1) Approximately $28 million, $18 million, and $143 million of the obligations included in joint-operating agreement payments, maintenance and service agreements, and FERC and other industry-related fees,
respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been
included in the table for presentation purposes.
Idaho Power's expense for operating leases was not material for the years ended 2021 and 2020.
Guarantees
Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the
WDEQ, was $51.6 million at December 31, 2021, representing IERCo's one-third share of BCC's total reclamation obligation of $154.7 million. BCC has a reclamation trust fund set
aside specifically for the purpose of paying these reclamation costs. At December 31, 2021, the value of the reclamation trust fund was $211.2 million. During 2021, the reclamation
trust fund made $21.1 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust
fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to
coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is
minimal.
Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that
may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the
overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood of incurring
costs under such indemnities based on its historical experience and the evaluation of the specific indemnities. As of December 31, 2021, management believes the likelihood is remote
that Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Idaho
Power has not recorded any liability on its balance sheets with respect to these indemnification obligations.
10. CONTINGENCIES
Restricted Stock and Performance-Based Shares AwardsRestricted Stock awards have three-year vesting periods and entitle the recipients to dividends or dividend equivalents, as applicable, and voting rights, except that holders ofrestricted stock units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition and subject to forfeiture under certaincircumstances. The fair value of these awards is based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period,reduced for any forfeitures during the vesting period.Performance-Based Shares awards have three-year vesting periods and entitle the recipients to voting rights, except that holders of performance-based units do not have voting rightsuntil the units are vested and settled in shares. Unvested awards are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to the attainment ofspecific performance conditions over the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and totalshareholder return (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and the year issued, the final number of shares awarded canrange from zero to 200 percent of the target award. Dividends or dividend equivalents, as applicable, are accrued during the vesting period and paid out based on the final number ofshares awarded.The grant-date fair value of the CEPS portion is based on the closing market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments.The fair value of this portion of the awards is charged to compensation expense over the requisite service period based on the estimated achievement of performance targets, reducedfor any forfeitures during the vesting period. The grant-date fair value of the TSR portion is estimated using the market value at the date of grant and a statistical model thatincorporates the probability of meeting performance targets based on historical returns relative to the peer group. The fair value of this portion of the awards is charged tocompensation expense over the requisite service period, provided the requisite service period is rendered, regardless of the level of TSR metric attained.A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Idaho Power share amounts represent shares of IDACORP common stock:Number ofShares/Units Weighted-AverageGrant DateFair ValueNonvested shares/units at January 1, 2021 156,013 $ 100.90Shares/units granted 95,821 87.76Shares/units forfeited (2,210)98.72Shares/units vested (75,415)87.24Nonvested shares/units at December 31, 2021 174,209 $ 99.61The total fair value of shares vested was $6.7 million in 2021 and $10.5 million in 2020. At December 31, 2021, Idaho Power had $7.5 million of total unrecognized compensationcost related to nonvested share-based compensation. These costs are expected to be recognized over a weighted-average period of 1.7 years. Original issue shares of IDACORP are usedfor these awards.In 2021, a total of 14,025 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at an average grant date fair value of $86.24 per share. Directorselected to defer receipt of 2,550 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.Compensation Expense: The following table shows Idaho Power's compensation cost recognized in income and the tax benefits resulting from the LTICP (in thousands of dollars):2021 2020Compensation cost $ 8,497 $ 7,339Income tax benefit 2,187 1,889No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the statements of income.9. COMMITMENTSPurchase ObligationsAt December 31, 2021, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):2022 2023 2024 2025 2026 ThereafterCogeneration and power production $ 298,867 $ 308,741 $ 311,968 $ 296,579 $ 293,508 $ 2,456,582Fuel62,287 19,328 8,663 8,362 8,354 58,355As of December 31, 2021, Idaho Power had 1,137 megawatt (MW) nameplate capacity of PURPA-related projects on-line, with an additional 75 MW nameplate capacity of projectsprojected to be on-line by 2024. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated withPURPA-related projects were approximately $200 million in 2021 and $194 million in 2020. In February 2022, Idaho Power entered into a 20-year power purchase agreement with aplanned 40 MW solar facility expected to be in service in 2023 which increased Idaho Power's contractual purchase obligations by approximately $78 million over the term of thecontract.Idaho Power also has the following long-term commitments (in thousands of dollars):2022 2023 2024 2025 2026 ThereafterJoint-operating agreement payments(1)$ 2,822 $ 2,822 $ 2,822 $ 2,822 $ 2,822 $ 14,110Easements and other payments 1,925 1,965 2,006 2,049 2,092 11,136Maintenance and service agreements(1)97,847 13,522 10,134 6,319 6,592 46,764FERC and other industry-related fees(1)16,772 14,549 14,174 14,174 14,174 70,870(1) Approximately $28 million, $18 million, and $143 million of the obligations included in joint-operating agreement payments, maintenance and service agreements, and FERC and other industry-related fees,respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has beenincluded in the table for presentation purposes.Idaho Power's expense for operating leases was not material for the years ended 2021 and 2020.GuaranteesIdaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with theWDEQ, was $51.6 million at December 31, 2021, representing IERCo's one-third share of BCC's total reclamation obligation of $154.7 million. BCC has a reclamation trust fund setaside specifically for the purpose of paying these reclamation costs. At December 31, 2021, the value of the reclamation trust fund was $211.2 million. During 2021, the reclamationtrust fund made $21.1 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trustfund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge tocoal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee isminimal.Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities thatmay arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, theoverall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood of incurringcosts under such indemnities based on its historical experience and the evaluation of the specific indemnities. As of December 31, 2021, management believes the likelihood is remotethat Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Idaho
Power has not recorded any liability on its balance sheets with respect to these indemnification obligations.
10. CONTINGENCIES10. CONTINGENCIES
Idaho Power has in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and
regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the
remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or
novel legal theories or a large number of parties. In accordance with applicable accounting guidance, Idaho Power establishes an accrual for legal proceedings when those matters
proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably
estimable, Idaho Power does not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and
reasonably estimable. As of the date of this report, Idaho Power's accruals for loss contingencies are not material to its financial statements as a whole; however, future accruals could
be material in a given period. Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures
involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and
appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted.
Idaho Power is party to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, records an accrual for associated loss
contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental
agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company's provision of electric service and the operation of its generation,
transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the western
United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and
criminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. Idaho Power has also regularly received claims by
governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power's transmission and distribution system. As of the date of this report, the
companies believe that resolution of existing claims will not have a material adverse effect on its financial statements.
Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on its
future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of
these regulations.
11. BENEFIT PLANS
Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k)
employee savings plan and provides certain post-employment benefits.
Pension Plans
Idaho Power has pension plans-a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit pension plans for certain senior management
employees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualified
defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under
these plans are based on years of service and the employee's final average earnings.
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Pension Plan SMSP
2021 2020 2021 2020
Change in projected benefit obligation:
Benefit obligation at January 1 $ 1,337,395 $ 1,134,752 $ 134,791 $ 122,443
Service cost 54,202 42,987 813 213
Interest cost 37,317 40,013 3,557 4,350
Actuarial (gain) loss (35,833)163,610 33 13,420
Plan amendment 130
Benefits paid (46,551)(43,967)(6,182)(5,765)
Projected benefit obligation at December 31 1,346,530 1,337,395 133,012 134,791
Change in plan assets:
Fair value at January 1 871,603 763,119
Actual return on plan assets 119,412 112,451
Employer contributions 40,000 40,000
Benefits paid (46,551)(43,967)
Fair value at December 31 984,464 871,603
Funded status at end of year $ (362,066)$ (465,792)$ (133,012)$ (134,791)
Amounts recognized in accumulated other comprehensive
income consist of:
Net loss $ 322,908 $ 437,859 $ 51,365 $ 55,537
Prior service cost 43 49 2,687 2,983
Subtotal 322,951 437,908 54,052 58,520
Less amount recorded as regulatory asset(1)(322,951)(437,908)
Net amount recognized in accumulated other comprehensive
income $$$ 54,052 $ 58,520
Accumulated benefit obligation $ 1,120,036 $ 1,115,923 $ 121,591 $ 119,517
(1) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive income for an unregulated entity are recorded as a regulatory asset for Idaho Power as Idaho
Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.
The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2021 are due primarily to increases in the assumed discount rates of both plans from
December 31, 2020, to December 31, 2021. The actuarial losses affecting the benefit obligations for the pension and SMSP plans in 2020 are due primarily to decreases in the assumed
discount rates from December 31, 2019, to December 31, 2020. For more information on discount rates, see "Plan Assumptions" below in this Note 11.
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for SMSP obligations. The Rabbi trust holds investments
in marketable securities and corporate-owned life insurance. The recorded value of these investments was approximately $117.1 million and $108.8 million at December 31, 2021 and
2020, respectively, and is reflected in Investments and in company-owned life insurance on the balance sheets.
The following table shows the components of net periodic pension cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, the
market-related value of assets is equal to the fair value of the assets.
Pension Plan SMSP
2021 2020 2021 2020
Service cost $ 54,202 $ 42,987 $ 813 $ 213
Interest cost 37,317 40,013 3,557 4,350
10. CONTINGENCIESIdaho Power has in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation andregulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) theremedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex ornovel legal theories or a large number of parties. In accordance with applicable accounting guidance, Idaho Power establishes an accrual for legal proceedings when those mattersproceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonablyestimable, Idaho Power does not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable andreasonably estimable. As of the date of this report, Idaho Power's accruals for loss contingencies are not material to its financial statements as a whole; however, future accruals couldbe material in a given period. Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosuresinvolve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible andappropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted.Idaho Power is party to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, records an accrual for associated losscontingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmentalagencies for damages for alleged personal injury, property damage, and economic losses, relating to the company's provision of electric service and the operation of its generation,transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the westernUnited States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages andcriminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. Idaho Power has also regularly received claims bygovernmental agencies and private landowners for damages for fires allegedly originating from Idaho Power's transmission and distribution system. As of the date of this report, thecompanies believe that resolution of existing claims will not have a material adverse effect on its financial statements.Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on itsfuture operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact ofthese regulations.11. BENEFIT PLANSIdaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k)employee savings plan and provides certain post-employment benefits.Pension PlansIdaho Power has pension plans-a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit pension plans for certain senior managementemployees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualifieddefined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits underthese plans are based on years of service and the employee's final average earnings.The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):Pension Plan SMSP202120202021 2020Change in projected benefit obligation:Benefit obligation at January 1 $ 1,337,395 $ 1,134,752 $ 134,791 $ 122,443Service cost 54,202 42,987 813 213Interest cost 37,317 40,013 3,557 4,350Actuarial (gain) loss (35,833)163,610 33 13,420Plan amendment 130Benefits paid (46,551)(43,967)(6,182)(5,765)Projected benefit obligation at December 31 1,346,530 1,337,395 133,012 134,791Change in plan assets:Fair value at January 1 871,603 763,119Actual return on plan assets 119,412 112,451Employer contributions 40,000 40,000Benefits paid (46,551)(43,967)Fair value at December 31 984,464 871,603Funded status at end of year $ (362,066)$ (465,792)$ (133,012)$ (134,791)Amounts recognized in accumulated other comprehensiveincome consist of:Net loss $ 322,908 $ 437,859 $ 51,365 $ 55,537Prior service cost 43 49 2,687 2,983Subtotal322,951 437,908 54,052 58,520Less amount recorded as regulatory asset(1)(322,951)(437,908)Net amount recognized in accumulated other comprehensiveincome $$$ 54,052 $ 58,520Accumulated benefit obligation $ 1,120,036 $ 1,115,923 $ 121,591 $ 119,517(1) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive income for an unregulated entity are recorded as a regulatory asset for Idaho Power as IdahoPower believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2021 are due primarily to increases in the assumed discount rates of both plans fromDecember 31, 2020, to December 31, 2021. The actuarial losses affecting the benefit obligations for the pension and SMSP plans in 2020 are due primarily to decreases in the assumeddiscount rates from December 31, 2019, to December 31, 2020. For more information on discount rates, see "Plan Assumptions" below in this Note 11.As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for SMSP obligations. The Rabbi trust holds investmentsin marketable securities and corporate-owned life insurance. The recorded value of these investments was approximately $117.1 million and $108.8 million at December 31, 2021 and2020, respectively, and is reflected in Investments and in company-owned life insurance on the balance sheets.The following table shows the components of net periodic pension cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, themarket-related value of assets is equal to the fair value of the assets.Pension Plan SMSP2021202020212020
Service cost $ 54,202 $ 42,987 $ 813 $ 213
Interest cost 37,317 40,013 3,557 4,350
Expected return on assets (64,090)(56,239)
Amortization of net loss 23,796 17,325 4,205 3,734
Amortization of prior service cost 6 6 296 290
Net periodic pension cost 51,231 44,092 8,871 8,587
Regulatory deferral of net periodic pension cost(1)(48,962)(42,042)
Previously deferred pension cost recognized(1)17,154 17,154
Net periodic pension cost recognized for financial reporting(1)$ 19,423 $ 19,204 $ 8,871 $ 8,587
(1) Net periodic pension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho
portion of net periodic pension cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.
The following table shows the components of other comprehensive (loss) income for the plans (in thousands of dollars):
Pension Plan SMSP
2021 2020 2021 2020
Actuarial gain (loss) during the year $ 91,156 $ (107,399)$ (33)$ (13,420)
Plan amendment service cost (130)
Reclassification adjustments for:
Amortization of net loss 23,796 17,325 4,205 3,734
Amortization of prior service cost 6 6 296 290
Adjustment for deferred tax effects (29,590)23,184 (1,150)2,452
Adjustment due to the effects of regulation (85,368)66,884
Other comprehensive income (loss)
recognized related to pension benefit plans $$$ 3,318 $ (7,074)
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
2022 2023 2024 2025 2026 2026-2030
Pension Plan $ 45,239 $ 47,038 $ 48,890 $ 50,850 $ 52,855 $ 293,409
SMSP 6,226 6,439 6,619 6,638 6,738 34,700
Idaho Power's funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more
than the maximum amount deductible for income tax purposes. In 2021 and 2020, Idaho Power elected to contribute more than the minimum required amounts in order to bring the
pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of the date of this report, Idaho
Power has no estimated minimum required contributions to the pension plan for 2022. Depending on market conditions and cash flow considerations in 2022, Idaho Power could
contribute up to $40 million to the pension plan during 2022 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions and
to mitigate the cost of being in an underfunded position.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee
group plan at the time of retirement as well as their spouses and qualifying dependents. Retirees hired on or after January 1, 1999, have access to the standard medical option at full
cost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth of Idaho Power's
future obligations under this plan.
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2021 2020
Change in accumulated benefit obligation:
Benefit obligation at January 1 $ 80,952 $ 71,029
Service cost 1,063 1,029
Interest cost 2,059 2,493
Actuarial (gain) loss (5,805)9,359
Benefits paid(1)(4,194)(2,958)
Benefit obligation at December 31 74,075 80,952
Change in plan assets:
Fair value of plan assets at January 1 41,311 39,625
Actual return on plan assets 6,308 5,248
Employer contributions(1)(1,961)(604)
Benefits paid(1)(4,194)(2,958)
Fair value of plan assets at December 31 41,464 41,311
Funded status at end of year (included in noncurrent liabilities)$ (32,611)$ (39,641)
(1) Contributions and benefits paid are each net of $3.0 million and $3.4 million of plan participant contributions for 2021 and 2020, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2021 2020
Net (gain) loss $ (8,020)$ 6,434
Prior service cost 80 127
Subtotal (7,940)6,561
Less amount recognized in regulatory assets 7,940 (6,561)
Net amount recognized in accumulated other comprehensive income $$
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
Expected return on assets (64,090)(56,239)Amortization of net loss 23,796 17,325 4,205 3,734Amortization of prior service cost 6 6 296 290Net periodic pension cost 51,231 44,092 8,871 8,587Regulatory deferral of net periodic pension cost(1)(48,962)(42,042)Previously deferred pension cost recognized(1)17,154 17,154Net periodic pension cost recognized for financial reporting(1)$ 19,423 $ 19,204 $ 8,871 $ 8,587(1) Net periodic pension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idahoportion of net periodic pension cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.The following table shows the components of other comprehensive (loss) income for the plans (in thousands of dollars):Pension Plan SMSP2021202020212020Actuarial gain (loss) during the year $ 91,156 $ (107,399)$ (33)$ (13,420)Plan amendment service cost (130)Reclassification adjustments for:Amortization of net loss 23,796 17,325 4,205 3,734Amortization of prior service cost 6 6 296 290Adjustment for deferred tax effects (29,590)23,184 (1,150)2,452Adjustment due to the effects of regulation (85,368)66,884Other comprehensive income (loss)recognized related to pension benefit plans $$$ 3,318 $ (7,074)The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):2022 2023 2024 2025 2026 2026-2030Pension Plan $ 45,239 $ 47,038 $ 48,890 $ 50,850 $ 52,855 $ 293,409SMSP6,226 6,439 6,619 6,638 6,738 34,700Idaho Power's funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not morethan the maximum amount deductible for income tax purposes. In 2021 and 2020, Idaho Power elected to contribute more than the minimum required amounts in order to bring thepension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of the date of this report, IdahoPower has no estimated minimum required contributions to the pension plan for 2022. Depending on market conditions and cash flow considerations in 2022, Idaho Power couldcontribute up to $40 million to the pension plan during 2022 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions andto mitigate the cost of being in an underfunded position.Postretirement BenefitsIdaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employeegroup plan at the time of retirement as well as their spouses and qualifying dependents. Retirees hired on or after January 1, 1999, have access to the standard medical option at fullcost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth of Idaho Power'sfuture obligations under this plan.The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):2021 2020Change in accumulated benefit obligation:Benefit obligation at January 1 $ 80,952 $ 71,029Service cost 1,063 1,029Interest cost 2,059 2,493Actuarial (gain) loss (5,805)9,359Benefits paid(1)(4,194)(2,958)Benefit obligation at December 31 74,075 80,952Change in plan assets:Fair value of plan assets at January 1 41,311 39,625Actual return on plan assets 6,308 5,248Employer contributions(1)(1,961)(604)Benefits paid(1)(4,194)(2,958)Fair value of plan assets at December 31 41,464 41,311Funded status at end of year (included in noncurrent liabilities)$ (32,611)$ (39,641)(1) Contributions and benefits paid are each net of $3.0 million and $3.4 million of plan participant contributions for 2021 and 2020, respectively.Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):2021 2020Net (gain) loss $ (8,020)$ 6,434Prior service cost 80 127Subtotal(7,940)6,561Less amount recognized in regulatory assets 7,940 (6,561)Net amount recognized in accumulated other comprehensive income $$
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2021 2020
Service cost $ 1,063 $ 1,029
Interest cost 2,059 2,493
Expected return on plan assets (2,395)(2,404)
Immediate recognition of loss from temporary deviation(1)4,736
Amortization of prior service cost 47 47
Net periodic postretirement benefit cost $ 5,510 $ 1,165
(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statement of income.
The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
2021 2020
Actuarial gain (loss) during the year $ 9,718 $ (6,515)
Reclassification adjustments for:
Immediate recognition of loss from temporary deviation(1)4,736
Reclassification adjustments for amortization of prior service cost 47 47
Adjustment for deferred tax effects (2,514)1,665
Adjustment due to the effects of regulation (11,987)4,803
Other comprehensive income related to postretirement benefit plans $$
(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statement of income.
The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):
2022 2023 2024 2025 2026 2026-2029
Expected benefit payments $ 5,447 $ 5,241 $ 4,982 $ 4,790 $ 4,557 $ 19,841
Plan Assumptions
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and
postretirement benefits plans:
Pension Plan SMSP
Postretirement
Benefits
2021 2020 2021 2020 2021 2020
Discount rate 3.05 %2.80 %3.00 %2.70 %2.95 %2.70 %
Rate of compensation increase(1)4.49 %4.43 %4.75 %4.75 %
Medical trend rate 6.3 %6.8 %
Dental trend rate 3.5 %4.0 %
Measurement date 12/31/2021 12/31/2020 12/31/2021 12/31/2020 12/31/2021 12/31/2020
(1) The 2021 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 2.09% composite merit increase component that is based on employees' years of
service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0.6% for employees in their fortieth year of service and beyond.
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:
Pension Plan SMSP
Postretirement
Benefits
2021 2020 2021 2020 2021 2020
Discount rate 2.80 %3.60 %2.70 %3.65 %2.70 %3.60 %
Expected long-term rate of
return on assets 7.40 %7.40 %6.00 %6.50 %
Rate of compensation increase 4.49 %4.43 %4.75 %4.75 %%
Medical trend rate 6.3 %6.8 %
Dental trend rate 3.5 %4.0 %
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.3 percent in 2021 and is assumed to decrease to
5.7 percent in 2022, 5.1 percent in 2023 and 2024, 5.0 percent in 2025 and to gradually decrease to 3.9 percent by 2074. The assumed dental cost trend rate used to measure the
expected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years.
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2021, for the pension asset portfolio by asset class is set forth below:
Asset Class
Target
Allocation
Actual
Allocation
December 31,
2021
Debt securities 24 %23 %
Equity securities 59 %61 %
Real estate 9 %8 %
Other plan assets 8 %8 %
Total 100 %100 %
Assets are rebalanced as necessary to keep the portfolio close to target allocations. The plan's principal investment objective is to maximize total return (defined as the sum of realized
interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is
placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants.
The three major goals in Idaho Power's asset allocation process are to:
determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
2021 2020Service cost $ 1,063 $ 1,029Interest cost 2,059 2,493Expected return on plan assets (2,395)(2,404)Immediate recognition of loss from temporary deviation(1)4,736Amortization of prior service cost 47 47Net periodic postretirement benefit cost $ 5,510 $ 1,165(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statement of income.The following table shows the components of other comprehensive income for the plan (in thousands of dollars):2021 2020Actuarial gain (loss) during the year $ 9,718 $ (6,515)Reclassification adjustments for:Immediate recognition of loss from temporary deviation(1)4,736Reclassification adjustments for amortization of prior service cost 47 47Adjustment for deferred tax effects (2,514)1,665Adjustment due to the effects of regulation (11,987)4,803Other comprehensive income related to postretirement benefit plans $$(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statement of income.The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):2022 2023 2024 2025 2026 2026-2029Expected benefit payments $ 5,447 $ 5,241 $ 4,982 $ 4,790 $ 4,557 $ 19,841Plan AssumptionsThe following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension andpostretirement benefits plans:Pension Plan SMSP PostretirementBenefits202120202021202020212020Discount rate 3.05 %2.80 %3.00 %2.70 %2.95 %2.70 %Rate of compensation increase(1)4.49 %4.43 %4.75 %4.75 %Medical trend rate 6.3 %6.8 %Dental trend rate 3.5 %4.0 %Measurement date 12/31/2021 12/31/2020 12/31/2021 12/31/2020 12/31/2021 12/31/2020(1) The 2021 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 2.09% composite merit increase component that is based on employees' years ofservice. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0.6% for employees in their fortieth year of service and beyond.The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:Pension Plan SMSP PostretirementBenefits202120202021202020212020Discount rate 2.80 %3.60 %2.70 %3.65 %2.70 %3.60 %Expected long-term rate ofreturn on assets 7.40 %7.40 %6.00 %6.50 %Rate of compensation increase 4.49 %4.43 %4.75 %4.75 %%Medical trend rate 6.3 %6.8 %Dental trend rate 3.5 %4.0 %The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.3 percent in 2021 and is assumed to decrease to5.7 percent in 2022, 5.1 percent in 2023 and 2024, 5.0 percent in 2025 and to gradually decrease to 3.9 percent by 2074. The assumed dental cost trend rate used to measure theexpected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years.Plan AssetsPension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2021, for the pension asset portfolio by asset class is set forth below:Asset Class TargetAllocation ActualAllocationDecember 31,2021Debt securities 24 %23 %Equity securities 59 %61 %Real estate 9 %8 %Other plan assets 8 %8 %Total 100 %100 %Assets are rebalanced as necessary to keep the portfolio close to target allocations. The plan's principal investment objective is to maximize total return (defined as the sum of realizedinterest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis isplaced on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants.The three major goals in Idaho Power's asset allocation process are to:
determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; andinstruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private equity funds, and cash and cash equivalents. With the
exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market
price.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has
delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index.
Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current
rate-of-return expectations are lower than the nominal returns generated over the past 30 years when interest rates were generally much higher.
Idaho Power's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a "worst-case" market scenario, to determine how much performance
could vary from the expected "average" performance over various time periods. This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and
investment style, provides the basis for managing the risk associated with investing portfolio assets.
Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level fair value hierarchy described in Note 16 - "Fair
Value Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars).
Level 1 Level 2 Level 3 Total
Assets at December 31, 2021
Cash and cash equivalents $ 24,636 $$$ 24,636
Intermediate bonds 39,133 187,048 226,181
Equity Securities: Large-Cap 104,318 104,318
Equity Securities: Mid-Cap 113,621 113,621
Equity Securities: Small-Cap 85,244 85,244
Equity Securities: Micro-Cap 42,915 42,915
Equity Securities: Global and International 67,625 67,625
Equity Securities: Emerging Markets 7,393 7,393
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and International 134,752
Commingled Fund: Equity Securities: Emerging Markets 47,332
Real estate 73,958
Private market investments 56,489
Total $ 484,885 $ 187,048 $$ 984,464
Postretirement plan assets(1)$ 2,391 $ 39,073 $$ 41,464
Level 1 Level 2 Level 3 Total
Assets at December 31, 2020
Cash and cash equivalents $ 25,008 $$$ 25,008
Intermediate bonds 34,455 163,000 197,455
Equity Securities: Large-Cap 79,259 79,259
Equity Securities: Mid-Cap 104,089 104,089
Equity Securities: Small-Cap 82,069 82,069
Equity Securities: Micro-Cap 44,715 44,715
Equity Securities: Global and International 69,687 69,687
Equity Securities: Emerging Markets 10,574 10,574
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and International 116,223
Commingled Fund: Equity Securities: Emerging Markets 50,019
Real estate 54,630
Private market investments 37,875
Total $ 449,856 $ 163,000 $$ 871,603
Postretirement plan assets(1)$ 1,333 $ 39,978 $$ 41,311
(1) The postretirement benefits assets are primarily life insurance contracts.
For the years ended December 31, 2021 and 2020, there were no material transfers into or out of Levels 1, 2, or 3.
Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States government and agency bonds, as well as the corporate
bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.
Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses.
The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account held
by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.
Commingled Funds: These funds, made up of global, international and emerging markets equity securities are measured at NAV, are not publicly traded, and therefore no publicly
quoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values
of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the
commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly
redemption following notice requirements of 5 to 7 days.
Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are not
frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including
property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by
property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial
statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; andmaintain a prudent risk profile consistent with ERISA fiduciary standards.Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private equity funds, and cash and cash equivalents. With theexception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon marketprice.Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class hasdelivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index.Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, currentrate-of-return expectations are lower than the nominal returns generated over the past 30 years when interest rates were generally much higher.Idaho Power's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a "worst-case" market scenario, to determine how much performancecould vary from the expected "average" performance over various time periods. This "worst-case" modeling, in addition to cash flow matching and diversification by asset class andinvestment style, provides the basis for managing the risk associated with investing portfolio assets.Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level fair value hierarchy described in Note 16 - "FairValue Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars).Level 1 Level 2 Level 3 TotalAssets at December 31, 2021Cash and cash equivalents $ 24,636 $$$ 24,636Intermediate bonds 39,133 187,048 226,181Equity Securities: Large-Cap 104,318 104,318Equity Securities: Mid-Cap 113,621 113,621Equity Securities: Small-Cap 85,244 85,244Equity Securities: Micro-Cap 42,915 42,915Equity Securities: Global and International 67,625 67,625Equity Securities: Emerging Markets 7,393 7,393Plan assets measured at NAV (not subject to hierarchy disclosure)Commingled Fund: Equity Securities: Global and International 134,752Commingled Fund: Equity Securities: Emerging Markets 47,332Real estate 73,958Private market investments 56,489Total$ 484,885 $ 187,048 $$ 984,464Postretirement plan assets(1)$ 2,391 $ 39,073 $$ 41,464Level 1 Level 2 Level 3 TotalAssets at December 31, 2020Cash and cash equivalents $ 25,008 $$$ 25,008Intermediate bonds 34,455 163,000 197,455Equity Securities: Large-Cap 79,259 79,259Equity Securities: Mid-Cap 104,089 104,089Equity Securities: Small-Cap 82,069 82,069Equity Securities: Micro-Cap 44,715 44,715Equity Securities: Global and International 69,687 69,687Equity Securities: Emerging Markets 10,574 10,574Plan assets measured at NAV (not subject to hierarchy disclosure)Commingled Fund: Equity Securities: Global and International 116,223Commingled Fund: Equity Securities: Emerging Markets 50,019Real estate 54,630Private market investments 37,875Total$ 449,856 $ 163,000 $$ 871,603Postretirement plan assets(1)$ 1,333 $ 39,978 $$ 41,311(1) The postretirement benefits assets are primarily life insurance contracts.For the years ended December 31, 2021 and 2020, there were no material transfers into or out of Levels 1, 2, or 3.Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States government and agency bonds, as well as the corporatebonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses.The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account heldby the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.Commingled Funds: These funds, made up of global, international and emerging markets equity securities are measured at NAV, are not publicly traded, and therefore no publiclyquoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The valuesof these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of thecommingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthlyredemption following notice requirements of 5 to 7 days.Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are notfrequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including
property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by
property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial
statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days writtenstatements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written
notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund's estimate of fair value at the end of the
quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other
redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or
encumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 9 years. The fund can be further extended with the approval of the limited
partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.
Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies based
on the estimated fair values of the underlying fund holdings divided by the fund shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fund
strategies utilize securities with readily available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including cost,
operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a quarterly basis with 70 days written notice. Redemptions
will be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amount
may be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adversely
impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding.
Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based
on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market
investments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. The
general partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption
rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.
Employee Savings Plan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches
specified percentages of employee contributions to the plan. Matching annual contributions were approximately $8.2 million and $7.9 million in 2021 and 2020, respectively.
Post-employment Benefits
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health
care benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employees
found to be disabled under Idaho Power's disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post-
employment benefits included in other deferred credits on Idaho Power's balance sheets at both December 31, 2021 and 2020, were approximately $2 million.
12. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS
The following table presents the major classifications of Idaho Power's utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and
accumulated provision for depreciation for the years ended December 31, 2021 and 2020 (in thousands of dollars):
2021 2020
Balance Avg Rate Balance Avg Rate
Production $ 2,597,285 3.15 %$ 2,529,708 3.23 %
Transmission 1,309,143 1.89 %1,272,360 1.88 %
Distribution 2,058,819 2.25 %1,968,752 2.26 %
General and Other 548,877 6.17 %517,079 6.17 %
Total in service 6,514,124 2.85 %6,287,899 2.88 %
Accumulated provision for depreciation (2,483,621)(2,376,165)
In service - net $ 4,030,503 $ 3,911,734
At December 31, 2021, Idaho Power's construction work in progress balance of $671.4 million included relicensing costs of $389.3 million for the HCC, Idaho Power's largest
hydropower complex. In 2021 and 2020, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the
effect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are
approved for recovery in base rates. At December 31, 2021, Idaho Power's provision for rate refund for collection of AFUDC relating to the HCC was $187.7 million.
Idaho Power's ownership interest in two jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating
utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the
Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at December 31, 2021 (in
thousands of dollars):
Name of Plant Location
Utility
Plant in
Service
Construction
Work in
Progress
Accumulated
Provision for
Depreciation Ownership %MW(1)(2)
Jim Bridger units 1-4 Rock Springs, WY $ 771,034 $ 7,775 $ 401,696 33 775
North Valmy unit 2(2)Winnemucca, NV 255,451 881 195,258 50 145
(1) Idaho Power's share of nameplate capacity.
(2) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2.
In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant, as planned. All depreciable property, plant and
equipment associated with Idaho Power's ownership in the Boardman power plant was fully depreciated as of December 31, 2020.
IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were $59.7 million in 2021 and $68.3 million in 2020.
Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power's power purchases from these facilities
were $8.2 million in 2021 and $9.3 million in 2020.
13. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value
when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost is
depreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As
a rate-regulated entity, Idaho Power records regulatory assets or liabilities instead of accretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assets
recorded under this order do not earn a return on investment. Accretion, depreciation, and gains or losses related to the Boardman generating facility have been exempted from such
regulatory treatment as Idaho Power collected amounts related to the decommissioning of Boardman in rates. In October 2020, Idaho Power and co-owner Portland General Electric
ceased coal-fired operations at their Boardman power plant. As of December 31, 2021 and 2020, Idaho Power has recorded a liability for estimated costs of decommissioning and
retirement of Boardman plant assets, which is included in the amounts in the table below.
Idaho Power's recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2021, changes in estimates at the coal-fired generation
facilities resulted in a net increase of $9.4 million in the recorded AROs. The increase is primarily related to revised cost estimates for the closure of a flue gas desulfurization pond at
the Jim Bridger plant.
Idaho Power also has additional AROs associated with its transmission system and generation facilities; however, due to the indeterminate removal date, the fair value of the
associated liabilities currently cannot be estimated and no amounts are recognized in the financial statements.
Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2021 2020
Balance at beginning of year $ 27,691 $ 28,191
statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days writtennotice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund's estimate of fair value at the end of thequarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with otherredemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate orencumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 9 years. The fund can be further extended with the approval of the limitedpartners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies basedon the estimated fair values of the underlying fund holdings divided by the fund shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fundstrategies utilize securities with readily available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including cost,operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a quarterly basis with 70 days written notice. Redemptionswill be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amountmay be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adverselyimpacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding.Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued basedon unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private marketinvestments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. Thegeneral partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemptionrights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.Employee Savings PlanIdaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matchesspecified percentages of employee contributions to the plan. Matching annual contributions were approximately $8.2 million and $7.9 million in 2021 and 2020, respectively.Post-employment BenefitsIdaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the healthcare benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employeesfound to be disabled under Idaho Power's disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post-employment benefits included in other deferred credits on Idaho Power's balance sheets at both December 31, 2021 and 2020, were approximately $2 million.12. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTSThe following table presents the major classifications of Idaho Power's utility plant in service, annual depreciation provisions as a percent of average depreciable balance, andaccumulated provision for depreciation for the years ended December 31, 2021 and 2020 (in thousands of dollars):2021 2020BalanceAvg Rate Balance Avg RateProduction$ 2,597,285 3.15 %$ 2,529,708 3.23 %Transmission 1,309,143 1.89 %1,272,360 1.88 %Distribution 2,058,819 2.25 %1,968,752 2.26 %General and Other 548,877 6.17 %517,079 6.17 %Total in service 6,514,124 2.85 %6,287,899 2.88 %Accumulated provision for depreciation (2,483,621)(2,376,165)In service - net $ 4,030,503 $ 3,911,734At December 31, 2021, Idaho Power's construction work in progress balance of $671.4 million included relicensing costs of $389.3 million for the HCC, Idaho Power's largesthydropower complex. In 2021 and 2020, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for theeffect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs areapproved for recovery in base rates. At December 31, 2021, Idaho Power's provision for rate refund for collection of AFUDC relating to the HCC was $187.7 million.Idaho Power's ownership interest in two jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participatingutility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in theStatements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at December 31, 2021 (inthousands of dollars):Name of Plant Location UtilityPlant inService ConstructionWork inProgress AccumulatedProvision forDepreciation Ownership %MW(1)(2)Jim Bridger units 1-4 Rock Springs, WY $ 771,034 $ 7,775 $ 401,696 33 775North Valmy unit 2(2)Winnemucca, NV 255,451 881 195,258 50 145(1) Idaho Power's share of nameplate capacity.(2) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2.In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant, as planned. All depreciable property, plant andequipment associated with Idaho Power's ownership in the Boardman power plant was fully depreciated as of December 31, 2020.IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were $59.7 million in 2021 and $68.3 million in 2020.Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power's power purchases from these facilitieswere $8.2 million in 2021 and $9.3 million in 2020.13. ASSET RETIREMENT OBLIGATIONS (ARO)The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair valuewhen incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carryingamount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost isdepreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. Asa rate-regulated entity, Idaho Power records regulatory assets or liabilities instead of accretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assetsrecorded under this order do not earn a return on investment. Accretion, depreciation, and gains or losses related to the Boardman generating facility have been exempted from suchregulatory treatment as Idaho Power collected amounts related to the decommissioning of Boardman in rates. In October 2020, Idaho Power and co-owner Portland General Electricceased coal-fired operations at their Boardman power plant. As of December 31, 2021 and 2020, Idaho Power has recorded a liability for estimated costs of decommissioning andretirement of Boardman plant assets, which is included in the amounts in the table below.Idaho Power's recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2021, changes in estimates at the coal-fired generationfacilities resulted in a net increase of $9.4 million in the recorded AROs. The increase is primarily related to revised cost estimates for the closure of a flue gas desulfurization pond atthe Jim Bridger plant.Idaho Power also has additional AROs associated with its transmission system and generation facilities; however, due to the indeterminate removal date, the fair value of theassociated liabilities currently cannot be estimated and no amounts are recognized in the financial statements.Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2021 2020
Balance at beginning of year $ 27,691 $ 28,191
Accretion expense 1,021 1,053
Revisions in estimated cash flows 9,415 193
Liability settled (1,429)(1,746)
Balance at end of year $ 36,698 $ 27,691
14. INVESTMENTS
The table below summarizes Idaho Power's investments as of December 31 (in thousands of dollars):
2021 2020
Idaho Power investments:
IERCO $ 27,909 $ 33,918
Exchange traded short-term bond funds and cash equivalents 54,078 50,531
Executive deferred compensation plan investments 353 202
Total Idaho Power investments $ 82,340 $ 84,651
Investments in Equity Securities
Investments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income. Unrealized gains and losses on equity securities
were immaterial at December 31, 2021 and December 31, 2020. The following table summarizes sales of equity securities (in thousands of dollars):
2021 2020
Proceeds from sales $ 11,328 $ 25,795
Gross realized gains from sales
15. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may
be influenced by market participants' nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses
derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary
objectives of Idaho Power's energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make
economic use of temporary surpluses that may develop.
All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases and
sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related
to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with
the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default.
Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types
of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-
cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below.
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2021 and 2020 (in thousands of dollars):
Location of Realized Gain/(Loss) on
Derivatives Recognized in Income
Gain/(Loss) on Derivatives Recognized in Income(1)
2021 2020
Financial swaps Operating revenues $ 1,046 $ 2,173
Financial swaps Purchased power 1,959 (3,531)
Financial swaps Fuel expense 12,180 (4,791)
Forward contracts Operating revenues 1,966 421
Forward contracts Purchased power (1,099)(384)
Forward contracts Fuel expense (194)(36)
(1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues or purchased power depending on the forecasted position being
economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives
are recorded in other O&M expense. See Note 16 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power's assets and
liabilities from price risk management activities.
Derivative Instrument Summary
The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross
amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2021 and 2020 (in thousands of dollars):
Asset Derivatives Liability Derivatives
Balance Sheet
Location
Gross
Fair
Value
Amounts
Offset
Net
Assets
Gross
Fair
Value
Amounts
Offset
Net
Liabilities
December 31,
2021
Current:
Financial swaps Other current assets $ 10,599 $ (4,893)(1)$ 5,706 $ 2,910 $ (2,910)$
Financial swaps
Other current
liabilities 20 20
Forward
contracts Other current assets 6 (4)2 4 (4)
Forward
contracts
Other current
liabilities 1,970 1,970
Long-term:
Financial swaps Other assets 899 (9)890 9 (9)
Financial swaps Other liabilities 14 14
Forward
contracts Other liabilities 3,743 3,743
Total $ 11,504 $ (4,906)$ 6,598 $ 8,670 $ (2,923)$ 5,747
Accretion expense 1,021 1,053Revisions in estimated cash flows 9,415 193Liability settled (1,429)(1,746)Balance at end of year $ 36,698 $ 27,69114. INVESTMENTSThe table below summarizes Idaho Power's investments as of December 31 (in thousands of dollars):2021 2020Idaho Power investments:IERCO $ 27,909 $ 33,918Exchange traded short-term bond funds and cash equivalents 54,078 50,531Executive deferred compensation plan investments 353 202Total Idaho Power investments $ 82,340 $ 84,651Investments in Equity SecuritiesInvestments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income. Unrealized gains and losses on equity securitieswere immaterial at December 31, 2021 and December 31, 2020. The following table summarizes sales of equity securities (in thousands of dollars):2021 2020Proceeds from sales $ 11,328 $ 25,795Gross realized gains from sales15. DERIVATIVE FINANCIAL INSTRUMENTSCommodity Price RiskIdaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk maybe influenced by market participants' nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power usesderivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primaryobjectives of Idaho Power's energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and makeeconomic use of temporary surpluses that may develop.All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases andsales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral relatedto derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts withthe counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default.Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These typesof transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below.The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2021 and 2020 (in thousands of dollars):Location of Realized Gain/(Loss) onDerivatives Recognized in Income Gain/(Loss) on Derivatives Recognized in Income(1)2021 2020Financial swaps Operating revenues $ 1,046 $ 2,173Financial swaps Purchased power 1,959 (3,531)Financial swaps Fuel expense 12,180 (4,791)Forward contracts Operating revenues 1,966 421Forward contracts Purchased power (1,099)(384)Forward contracts Fuel expense (194)(36)(1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues or purchased power depending on the forecasted position beingeconomically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivativesare recorded in other O&M expense. See Note 16 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power's assets andliabilities from price risk management activities.Derivative Instrument SummaryThe table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the grossamounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2021 and 2020 (in thousands of dollars):Asset Derivatives Liability DerivativesBalance SheetLocation GrossFairValue AmountsOffset NetAssets GrossFairValue AmountsOffset NetLiabilitiesDecember 31,2021Current:Financial swaps Other current assets $ 10,599 $ (4,893)(1)$ 5,706 $ 2,910 $ (2,910)$Financial swaps Other currentliabilities 20 20ForwardcontractsOther current assets 6 (4)2 4 (4)Forwardcontracts Other currentliabilities 1,970 1,970Long-term:Financial swaps Other assets 899 (9)890 9 (9)
Financial swaps Other liabilities 14 14
Forward
contracts Other liabilities 3,743 3,743
Total $ 11,504 $ (4,906)$ 6,598 $ 8,670 $ (2,923)$ 5,747Total$ 11,504 $ (4,906)$ 6,598 $ 8,670 $ (2,923)$ 5,747
December 31,
2020
Current:
Financial swaps Other current assets $ 2,028 $ (36)$ 1,992 $ 36 $ (36)$
Financial swaps
Other current
liabilities 187 (187)786 (652)
(2)
134
Forward
contracts Other current assets 5 (2)3
2
(2)
Forward
contracts
Other current
liabilities
3
(3)13 (3)10
Long-term:
Financial swaps Other liabilities 40 (40)56 (56)(2)
Total $ 2,263 $ (268)$ 1,995 $ 893 $ (749)$ 144
(1) Current asset derivative amounts offset include $2.0 million of collateral payable at December 31, 2021.
(2) Current and long-term liability derivative amounts offset include $0.5 million and $16 thousand of collateral receivable at December 31, 2020, respectively.
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2021 and 2020 (in thousands of units):
December 31,
Commodity Units 2021 2020
Electricity purchases MWh 529 74
Electricity sales MWh 129
Natural gas purchases MMBtu 11,740 7,923
Natural gas sales MMBtu 775
Credit Risk
At December 31, 2021, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through
reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by
establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their
affiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy
Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequate
assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors
Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the
counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net
liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2021, was $3.0
million. Idaho Power did not post any cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31,
2021, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $7.6 million to cover open liability positions as well as completed
transactions that have not yet been paid.
16. FAIR VALUE MEASUREMENTS
Idaho Power has categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy
gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to
measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of
the instrument.
Financial assets and liabilities recorded on the balance sheets are categorized based on the inputs to the valuation techniques as follows:
Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that Idaho Power has the ability to
access.
Level 2: Financial assets and liabilities whose values are based on the following:
a) quoted prices for similar assets or liabilities in active markets;
b) quoted prices for identical or similar assets or liabilities in non-active markets;
c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term
of the asset or liability.
Idaho Power Level 2 inputs for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data.
Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair
value measurement. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Idaho Power's assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their
placement within the fair value hierarchy. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2021 and
2020.
The following table presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of December 31, 2021 and 2020 (in thousands of
dollars):
December 31, 2021 December 31, 2020
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets:
Money market funds and commercial
paper
$ 10,393 $$
$ 10,393
$ 40,038 $$
$ 40,038
Derivatives 6,596 2 6,598 1,995 1,995
Equity securities 54,431 54,431 50,733 50,733
Liabilities:
Derivatives $ 34 $ 5,713 $$ 5,747 $ 134 $ 10 $$ 144
Idaho Power's derivatives are contracts entered into as part of its management of loads and resources. Electricity swap derivatives are valued on the Intercontinental Exchange with
quoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forward
contract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange and Intercontinental Exchange pricing, adjusted for location basis, which are also quoted
under NYMEX and ICE pricing. Equity securities at Idaho Power consist of employee-directed investments related to an executive deferred compensation plan and actively traded
money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a Rabbi trust.
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2021 and 2020, using available
Total $ 11,504 $ (4,906)$ 6,598 $ 8,670 $ (2,923)$ 5,747December 31,2020Current:Financial swaps Other current assets $ 2,028 $ (36)$ 1,992 $ 36 $ (36)$Financial swaps Other currentliabilities 187 (187)786 (652)(2)134ForwardcontractsOther current assets 5 (2)3 2 (2)Forwardcontracts Other currentliabilities 3 (3)13 (3)10Long-term:Financial swaps Other liabilities 40 (40)56 (56)(2)Total $ 2,263 $ (268)$ 1,995 $ 893 $ (749)$ 144(1) Current asset derivative amounts offset include $2.0 million of collateral payable at December 31, 2021.(2) Current and long-term liability derivative amounts offset include $0.5 million and $16 thousand of collateral receivable at December 31, 2020, respectively.The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2021 and 2020 (in thousands of units):December 31,Commodity Units 2021 2020Electricity purchases MWh 529 74Electricity sales MWh 129Natural gas purchases MMBtu 11,740 7,923Natural gas sales MMBtu 775Credit RiskAt December 31, 2021, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure throughreviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks byestablishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or theiraffiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American EnergyStandards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequateassurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.Credit-Contingent FeaturesCertain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's InvestorsService and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and thecounterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in netliability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2021, was $3.0million. Idaho Power did not post any cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31,2021, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $7.6 million to cover open liability positions as well as completedtransactions that have not yet been paid.16. FAIR VALUE MEASUREMENTSIdaho Power has categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchygives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used tomeasure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement ofthe instrument.Financial assets and liabilities recorded on the balance sheets are categorized based on the inputs to the valuation techniques as follows:Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that Idaho Power has the ability toaccess.Level 2: Financial assets and liabilities whose values are based on the following:a) quoted prices for similar assets or liabilities in active markets;b) quoted prices for identical or similar assets or liabilities in non-active markets;c) pricing models whose inputs are observable for substantially the full term of the asset or liability; andd) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full termof the asset or liability.Idaho Power Level 2 inputs for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data.Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fairvalue measurement. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.Idaho Power's assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and theirplacement within the fair value hierarchy. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2021 and2020.The following table presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of December 31, 2021 and 2020 (in thousands ofdollars):December 31, 2021 December 31, 2020Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 TotalAssets:Money market funds and commercialpaper $ 10,393 $$$ 10,393 $ 40,038 $$$ 40,038Derivatives6,596 2 6,598 1,995 1,995Equity securities 54,431 54,431 50,733 50,733Liabilities:Derivatives $ 34 $ 5,713 $$ 5,747 $ 134 $ 10 $$ 144Idaho Power's derivatives are contracts entered into as part of its management of loads and resources. Electricity swap derivatives are valued on the Intercontinental Exchange withquoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forward
contract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange and Intercontinental Exchange pricing, adjusted for location basis, which are also quoted
under NYMEX and ICE pricing. Equity securities at Idaho Power consist of employee-directed investments related to an executive deferred compensation plan and actively traded
money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a Rabbi trust.
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2021 and 2020, using availableThe table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2021 and 2020, using available
market information and appropriate valuation methodologies (in thousands).
December 31, 2021 December 31, 2020
Carrying
Amount
Estimated Fair
Value
Carrying
Amount
Estimated Fair
Value
(thousands of dollars)
Liabilities:
Long-term debt (including current
portion)(1)$ 2,015,982 $ 2,381,172 $ 2,016,848 $ 2,466,967
(1) Long-term debt is categorized as Level 2 of the fair value hierarchy, as defined earlier in this Note 16 - "Fair Value Measurements."
Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and
other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value.
17. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI),
net of tax, during the years ended December 31, 2021 and 2020 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.
Year Ended December 31,
2021 2020
Defined benefit pension items
Balance at beginning of period $ (43,358)$ (36,284)
Other comprehensive income before reclassifications, net of tax of
$(8) and $(3,488)(25)(10,062)
Amounts reclassified out of AOCI to net income, net of tax of $1,158
and $1,036 3,343 2,988
Net current-period other comprehensive income 3,318 (7,074)
Balance at end of period $ (40,040)$ (43,358)
The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the
years ended December 31, 2021 and 2020 (in thousands of dollars). Items in parentheses indicate increases to net income.
Amount Reclassified from AOCI
Year Ended December 31,
2021 2020
Amortization of defined benefit pension items(1)
Prior service cost $ 296 $ 290
Net loss 4,205 3,734
Total before tax 4,501 4,024
Tax benefit(2)(1,158)(1,036)
Net of tax 3,343 2,988
Total reclassification for the period $ 3,343 $ 2,988
(1) Amortization of these items is included in "Other (income) expense, net" in the income statements of Idaho Power.
(2) The tax benefit is included in "Income tax expense" in the income statements of Idaho Power.
18. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs
of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.8 million in 2021 and $0.7 million in 2020.
At December 31, 2021 and 2020, Idaho Power had a $2.0 million and $1.5 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance
on its balance sheets.
Ida-West: Ida-West Energy Company (Ida-West) is a wholly-owned subsidiary of IDACORP and is an operator of small hydropower generation projects that satisfy the requirements of
the Public Utility Regulatory Policies Act of 1978. Idaho Power purchases all of the power generated by four of Ida-West's hydropower projects located in Idaho. Idaho Power
purchased $8.2 million in 2021 and $9.3 million in 2020 of power from Ida-West.
38
FERC FORM No. 1 (ED. 12-96)
Page 122-123
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Item
(a)
Unrealized Gains and
Losses on Available-For-
Sale Securities
(b)
Minimum Pension Liability
Adjustment (net amount)
(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow
Hedges Interest Rate
Swaps
(f)
Other
Cash
Flow
Hedges
[Specify]
(g)
Totals for
each category
of items
recorded in
Account 219
(h)
Net Income
(Carried
Forward from
Page 116,
Line 78)
(i)
Total
Comprehensive
Income
(j)
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
1 Balance of Account 219 at Beginning of
Preceding Year 0 (36,283,823)(36,283,823)
2
Preceding Quarter/Year to Date
Reclassifications from Account 219 to Net
Income
0 2,988,104 2,988,104
3 Preceding Quarter/Year to Date Changes in
Fair Value 0 (10,061,961)(10,061,961)
4 Total (lines 2 and 3)0 0 0 (7,073,857)0 0 (7,073,857)233,234,543 226,160,686
5 Balance of Account 219 at End of Preceding
Quarter/Year 0 0 0 (43,357,680)0 0 (43,357,680)
6 Balance of Account 219 at Beginning of
Current Year 0 0 0 (43,357,680)0 0 (43,357,680)
7 Current Quarter/Year to Date Reclassifications
from Account 219 to Net Income 0 3,343,179 3,343,179
8 Current Quarter/Year to Date Changes in Fair
Value 0 (25,393)(25,393)
9 Total (lines 7 and 8)0 0 0 3,317,786 0 0 3,317,786 243,225,299 246,543,085
10 Balance of Account 219 at End of Current
Quarter/Year 0 0 0 (40,039,894)0 0 (40,039,894)
FERC FORM No. 1 (NEW 06-02)
Page 122 (a)(b)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Line
No.
Classification
(a)
Total Company For the Current
Year/Quarter Ended
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other
(Specify)
(g)
Common
(h)
1 UTILITY PLANT
2 In Service
3 Plant in Service (Classified)6,508,861,593 6,508,861,593
4 Property Under Capital Leases 0
5 Plant Purchased or Sold 0
6 Completed Construction not Classified 0
7 Experimental Plant Unclassified 0
8 Total (3 thru 7)6,508,861,593 6,508,861,593
9 Leased to Others 0
10 Held for Future Use 4,511,192 4,511,192
11 Construction Work in Progress 671,424,756 671,424,756
12 Acquisition Adjustments 750,893 750,893
13 Total Utility Plant (8 thru 12)7,185,548,434 7,185,548,434
14 Accumulated Provisions for Depreciation, Amortization,
& Depletion 2,483,620,791 2,483,620,791
15 Net Utility Plant (13 less 14)4,701,927,643 4,701,927,643 0 0 0 0 0
16 DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION, AMORTIZATION AND DEPLETION
17 In Service:
18 Depreciation 2,444,332,482 2,444,332,482
19 Amortization and Depletion of Producing Natural Gas
Land and Land Rights 0
20 Amortization of Underground Storage Land and Land
Rights 0
21 Amortization of Other Utility Plant 39,195,699 39,195,699
22 Total in Service (18 thru 21)2,483,528,181 2,483,528,181
23 Leased to Others
24 Depreciation 0
25 Amortization and Depletion 0
26 Total Leased to Others (24 & 25)0
27 Held for Future Use
28 Depreciation 0
29 Amortization 0
30 Total Held for Future Use (28 & 29)0
31 Abandonment of Leases (Natural Gas)0
32 Amortization of Plant Acquisition Adjustment 92,610 92,610
33 Total Accum Prov (equals 14) (22,26,30,31,32)2,483,620,791 2,483,620,791
FERC FORM No. 1 (ED. 12-89)
Page 200-201
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Line
No.
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End
of Year
(g)
1 1. INTANGIBLE PLANT
2 (301) Organization 5,703 5,703
3 (302) Franchise and Consents 35,139,517 2,937,366 38,076,883
4 (303) Miscellaneous Intangible Plant 40,995,899 5,379,696 1,863,136 44,512,459
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)76,141,119 8,317,062 1,863,136 0 0 82,595,045
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights 1,722,421 1,722,421
9 (311) Structures and Improvements 120,328,639 660,972 43,710 120,945,901
10 (312) Boiler Plant Equipment 640,794,248 10,787,371 3,428,204 648,153,415
11 (313) Engines and Engine-Driven Generators 0
12 (314) Turbogenerator Units 138,531,672 2,146,414 62,435 140,615,651
13 (315) Accessory Electric Equipment 53,352,826 784,767 35,719 54,101,874
14 (316) Misc. Power Plant Equipment 17,791,940 1,973,777 613,221 19,152,496
15 (317) Asset Retirement Costs for Steam Production 15,446,594 11,093,610 26,540,204
16 TOTAL Steam Production Plant (Enter Total of lines 8
thru 15)987,968,340 27,446,911 4,183,289 0 0 1,011,231,962
17 B. Nuclear Production Plant
18 (320) Land and Land Rights 0
19 (321) Structures and Improvements 0
20 (322) Reactor Plant Equipment 0
21 (323) Turbogenerator Units 0
22 (324) Accessory Electric Equipment 0
23 (325) Misc. Power Plant Equipment 0
24 (326) Asset Retirement Costs for Nuclear Production 0
25 TOTAL Nuclear Production Plant (Enter Total of lines 18
thru 24)0 0 0 0 0 0
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 31,942,133 56,475 31,998,608
28 (331) Structures and Improvements 227,499,486 17,983,354 154,092 245,328,748
29 (332) Reservoirs, Dams, and Waterways 288,709,176 12,439,899 257,307 300,891,768
30 (333) Water Wheels, Turbines, and Generators 331,230,179 10,747,638 1,331,604 340,646,213
31 (334) Accessory Electric Equipment 66,629,844 1,737,860 48,996 68,318,708
32 (335) Misc. Power Plant Equipment 28,563,626 1,954,677 1,265,088 29,253,215
33 (336) Roads, Railroads, and Bridges 13,962,996 827,202 14,790,198
34 (337) Asset Retirement Costs for Hydraulic Production 0
35 TOTAL Hydraulic Production Plant (Enter Total of lines
27 thru 34)988,537,440 45,747,105 3,057,087 0 0 1,031,227,458
36 D. Other Production Plant
37 (340) Land and Land Rights 2,699,794 2,699,794
38 (341) Structures and Improvements 154,240,605 518,674 170,299 154,588,980
39 (342) Fuel Holders, Products, and Accessories 10,438,248 8,014 10,446,262
40 (343) Prime Movers 220,475,074 2,580,621 1,628,409 221,427,286
41 (344) Generators 66,678,480 66,678,480
42 (345) Accessory Electric Equipment 92,002,588 88,397 8,717 92,082,268
43 (346) Misc. Power Plant Equipment 6,667,605 288,548 53,968 6,902,185
44 (347) Asset Retirement Costs for Other Production 0
44.1 (348) Energy Storage Equipment - Production 0
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)553,202,394 3,484,254 1,861,393 0 0 554,825,255
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and
45)2,529,708,174 76,678,270 9,101,769 0 0 2,597,284,675
47 3. Transmission Plant
48 (350) Land and Land Rights 39,152,441 464,527 39,616,968
48.1 (351) Energy Storage Equipment - Transmission 0
49 (352) Structures and Improvements 85,528,072 1,990,141 44,665 87,473,548
50 (353) Station Equipment 462,306,900 11,322,266 3,503,138 470,126,028
51 (354) Towers and Fixtures 222,850,576 9,145,852 665,784 231,330,644
52 (355) Poles and Fixtures 217,371,229 8,690,441 1,897,966 224,163,704
53 (356) Overhead Conductors and Devices 244,760,635 12,418,610 1,137,396 256,041,849
54 (357) Underground Conduit 0
55 (358) Underground Conductors and Devices 0
FERC FORM No. 1 (REV. 12-05)
Page 204-207
56 (359) Roads and Trails 390,266 390,266
57 (359.1) Asset Retirement Costs for Transmission Plant 0
58 TOTAL Transmission Plant (Enter Total of lines 48 thru
57)1,272,360,119 44,031,837 7,248,949 0 0 1,309,143,007
59 4. Distribution Plant
60 (360) Land and Land Rights 7,429,777 403,128 1,589 7,831,316
61 (361) Structures and Improvements 50,879,274 1,431,793 141,408 52,169,659
62 (362) Station Equipment 287,263,364 15,292,957 1,138,684 301,417,637
63 (363) Energy Storage Equipment – Distribution 0
64 (364) Poles, Towers, and Fixtures 293,142,664 20,692,496 6,711,338 307,123,822
65 (365) Overhead Conductors and Devices 147,320,762 8,250,790 3,452,585 152,118,967
66 (366) Underground Conduit 53,566,218 175,347 389,624 53,351,941
67 (367) Underground Conductors and Devices 302,975,749 12,654,838 2,021,096 313,609,491
68 (368) Line Transformers 647,632,805 43,600,708 7,314,115 683,919,398
69 (369) Services 64,812,030 2,212,415 659,074 66,365,371
70 (370) Meters 104,876,452 9,259,659 4,067,852 110,068,259
71 (371) Installations on Customer Premises 4,004,512 1,406,049 125,929 5,284,632
72 (372) Leased Property on Customer Premises 0
73 (373) Street Lighting and Signal Systems 4,848,520 1,320,993 611,198 5,558,315
74 (374) Asset Retirement Costs for Distribution Plant 0
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1,968,752,127 116,701,173 26,634,492 0 0 2,058,818,808
76 5. REGIONAL TRANSMISSION AND MARKET
OPERATION PLANT
77 (380) Land and Land Rights 0
78 (381) Structures and Improvements 0
79 (382) Computer Hardware 0
80 (383) Computer Software 0
81 (384) Communication Equipment 0
82 (385) Miscellaneous Regional Transmission and Market
Operation Plant 0
83 (386) Asset Retirement Costs for Regional Transmission
and Market Oper 0
84 TOTAL Transmission and Market Operation Plant (Total
lines 77 thru 83)0 0 0 0 0 0
85 6. General Plant
86 (389) Land and Land Rights 18,862,345 1,828,167 20,690,512
87 (390) Structures and Improvements 136,316,242 8,275,237 3,452,753 141,138,726
88 (391) Office Furniture and Equipment 43,713,591 4,477,027 5,186,934 43,003,684
89 (392) Transportation Equipment 113,294,310 4,982,084 8,984,330 109,292,064
90 (393) Stores Equipment 4,383,296 (59,455)44,524 4,279,317
91 (394) Tools, Shop and Garage Equipment 12,275,962 271,155 190,033 12,357,084
92 (395) Laboratory Equipment 14,859,117 801,400 881,169 14,779,348
93 (396) Power Operated Equipment 23,706,548 634,631 413,809 23,927,370
94 (397) Communication Equipment 60,519,006 22,726,332 1,903,238 81,342,100
95 (398) Miscellaneous Equipment 8,147,401 2,265,017 202,565 10,209,853
96 SUBTOTAL (Enter Total of lines 86 thru 95)436,077,818 46,201,595 21,259,355 0 0 461,020,058
97 (399) Other Tangible Property 0
98 (399.1) Asset Retirement Costs for General Plant 0
99 TOTAL General Plant (Enter Total of lines 96, 97, and 98)436,077,818 46,201,595 21,259,355 0 0 461,020,058
100 TOTAL (Accounts 101 and 106)6,283,039,357 291,929,937 66,107,701 0 0 6,508,861,593
101 (102) Electric Plant Purchased (See Instr. 8)0
102 (Less) (102) Electric Plant Sold (See Instr. 8)0
103 (103) Experimental Plant Unclassified 0
104 TOTAL Electric Plant in Service (Enter Total of lines 100
thru 103)6,283,039,357 291,929,937 66,107,701 0 0 6,508,861,593
FERC FORM No. 1 (REV. 12-05)
Page 204-207
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Line
No.
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End
of Year
(g)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Line
No.
Description and Location of Property
(a)
Date Originally Included in This Account
(b)
Date Expected to be used in Utility Service
(c)
Balance at End of Year
(d)
1 Land and Rights:
2 Distribution Line 25,581
3
4 Column B and C if no date listed it is various
5 Production 109,962
6 Transmission Lines 68,592
7
8 Line #854 500 Kv 03/31/2009 12/31/2030 308,066
9 Transmission Stations 423,089
10 Homedale Substation 02/29/2008 12/31/2035 109,453
11
12 Line #853 500Kv 12/16/2011 12/31/2026 329,529
13 Distribution Stations 1,462,556
14 Pallette Junction Substation 03/15/2021 12/31/2030 744,012
15
16
21 Other Property:
22 Transmission Stations 199,069
23 Distribution Stations 69,941
24 Homedale Substation 02/29/2008 12/31/2035 217,797
25 Underground Vault, Blaine County 08/30/2016 12/31/2024 443,545
26 Column B and C if no date listed it is various
47 TOTAL 4,511,192
FERC FORM No. 1 (ED. 12-96)
Page 214
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Line No.Description of Project
(a)
Construction work in progress - Electric (Account 107)
(b)
1. Report below descriptions and balances at end of year of projects in process of construction (107).
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts).
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
1 ROLLUP RELIC COST BROWNLEE 150,917,625
2 ROLLUP RELIC COST HELLS CANYON 102,662,331
3 GATEWAY WEST 500KV LINE 48,101,626
4 ROLLUP RELIC COST OXBOW 47,880,729
5 HELLS CANYON RELICENSING OUTSI 42,217,096
6 B2H PERMITTING 11/1/2011 & FOR 25,572,620
7 LOWER SALMON UNIT 1 REFURBISHM 12,107,093
8 BOARDMAN - HEMINGWAY 500 KV LI 11,665,236
9 HELLS CANYON GENERATOR REFURBI 11,468,650
10 WQ HCC401 CERTIFICATION OPS AN 10,167,348
11 HCC WATERSHED ENHANCEMENT PROG 10,026,014
12 HCC SNAKE RIVER ENHANCEMENT RE 8,453,263
13 LEGAL DEPT. LABOR FOR RELICENS 7,364,903
14 BOC YARD EXPANSION AND PARKING 5,937,149
15 BULL TROUT PROGRAM - ADMINISTR 5,588,660
16 REL-HCC OREGON REAUTHORIZATION 5,207,716
17 LTP - MAJOR INSPECTION 4,914,270
18 RGSS200001 ROGERSON SWITCHING 4,263,626
19 BROWNLEE SECURITY FENCE 4,258,857
20 B2H TLINE CONSTRUCTION COSTS 4,200,814
21 SHSH170002 INSTALL 138KV TIE B 4,154,310
22 HC SEDIMENT PROGRAMS 3,600,939
23 FALL CHINOOK PROGRAM - REDD SU 3,513,025
24 LOWER SALMON UNIT 3 REFURB 3,511,476
25 WDRI-KCHM NEW 138KV 3,361,228
26 OXBOW HATCHERY RENOVATION 3,322,426
27 REPORTING MODEL FOR SNAKE RIVE 3,239,166
28 HCPR190001 - HCPR PLANT MODERN 3,044,373
29 HELLS CANYON GENERATOR REFURBI 2,668,991
30 T253180001- 69 KV MTNHM CANYON 2,634,744
31 WHITE STURGEON PROGRAM - HCC R 2,495,859
32 BRIDGER 2017C100 CCR JB FGD PO 2,431,197
33 BOCB170034 - MBE 9 PURCHASE A 2,390,144
34 RECORDS CENTER DESIGN AND REMO 2,388,598
35 GOWN210001- ADD SECOND TRANSFO 2,161,322
36 MY ACCOUNT 4 (FORMERLY AUTO PA 2,132,329
37 BLPR190001 - SWITCHYARD PERIME 2,061,269
38 NEWX170002 - MORA/HBRD CLBA LI 1,976,897
39 ST - HP TURBINE OVERHAUL 1,754,347
40 AFPR TURBINE GENERATOR REFURB 1,747,401
41 CAPITAL 2020 - SAND SPRINGS FL 1,723,695
42 KNYN160001 - REPLACE T061 AND 1,721,054
43 LSPR LOCAL SERVICE UPGRADE PHA 1,457,276
44 ELMR150001 REPLACE 061A, 062A,1,310,469
45 COMMON ASSET: MPSN 500KV FENCE 1,303,864
46 REPLACE UNIT 8320 WITH 8524 -1,301,708
47 OXBOW SPILLWAY REHABILITATION 1,267,520
48 COMMON ASSET: MPSN 345KV FENCE 1,180,604
49 OXBOW BYPASS FLOW PIPE RELOCAT 1,169,642
50 FALL CHINOOK PROGRAM - ENTRAPM 1,123,715
51 TRIBUTARY ENHANCEMENT RESEARCH 1,122,860
52 ELMR220001 - ADD 4MW BATTERY S 1,089,493
53 BOBN220001 (BDSS) - 44.8MVA TR 1,016,543
54 MY ACCOUNT - RELEASE 6 1,016,330
55 HELLS CANYON NOAA BIOLOGICAL A 1,004,287
56 Other Minor Projects Under $1,000,000 75,050,029
43 Total 671,424,756
FERC FORM No. 1 (ED. 12-87)
Page 216
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Line
No.
Item
(a)
Total (c + d + e)
(b)
Electric Plant in Service
(c)
Electric Plant Held for Future Use
(d)
Electric Plant Leased To Others
(e)
Section A. Balances and Changes During Year
1 Balance Beginning of Year 2,343,768,007 2,343,768,007
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense 165,446,697 165,446,697
4 (403.1) Depreciation Expense for Asset Retirement Costs 0
5 (413) Exp. of Elec. Plt. Leas. to Others 0 0
6 Transportation Expenses-Clearing 5,482,332 5,482,332
7 Other Clearing Accounts 0 0
8 Other Accounts (Specify, details in footnote):
9.1 Fuel Stock 31,008 31,008
10 TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)170,960,037 170,960,037 0 0
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired (64,242,972)(64,242,972)
13 Cost of Removal (15,723,352)(15,723,352)
14 Salvage (Credit)8,670,640 8,670,640
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)(71,295,684)(71,295,684)0 0
16 Other Debit or Cr. Items (Describe, details in footnote):
17.1 (a)
Valmy Depreciation Adjustments 900,122 900,122
18 Book Cost or Asset Retirement Costs Retired 0 0
19 Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)2,444,332,482 2,444,332,482 0 0
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 594,596,029 594,596,029
21 Nuclear Production 0 0
22 Hydraulic Production-Conventional 479,422,968 479,422,968
23 Hydraulic Production-Pumped Storage 0 0
24 Other Production 150,061,405 150,061,405
25 Transmission 403,959,695 403,959,695
26 Distribution 686,873,398 686,873,398
27 Regional Transmission and Market Operation 0 0
28 General 129,418,987 129,418,987
29 TOTAL (Enter Total of lines 20 thru 28)2,444,332,482 2,444,332,482 0 0
FERC FORM No. 1 (REV. 12-05)
Page 219
FOOTNOTE DATA
(a) Concept: OtherAdjustmentsToAccumulatedDepreciationDescription
Page 219 Line 16:Valmy depreciation adjustments (ID 33771 and OR 17-235), CIAC and Asset Retirement Obligation activity.
FERC FORM No. 1 (REV. 12-05)
Page 219
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Line
No.
Description of Investment
(a)
Date Acquired
(b)
Date of Maturity
(c)
Amount of Investment at
Beginning of Year
(d)
Equity in Subsidiary Earnings
of Year
(e)
Revenues
for Year
(f)
Amount of
Investment
at End of
Year
(g)
Gain or
Loss from
Investment
Disposed
of
(h)
1 Common Stock 02/01/1974 500 500
2 Capital Contributions 2,462,593 2,462,593
3 Equity in Earnings 31,455,037 8,991,348 15,000,000 25,446,385
42 Total Cost of Account 123.1 $2,463,094 Total 33,918,130 8,991,348 15,000,000 27,909,478 0
FERC FORM No. 1 (ED. 12-89)
Page 224-225
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
MATERIALS AND SUPPLIES
Line
No.
Account
(a)
Balance Beginning of Year
(b)
Balance End of Year
(c)
Department or Departments which Use Material
(d)
1 Fuel Stock (Account 151)31,645,944 18,045,117
2 Fuel Stock Expenses Undistributed (Account 152)0
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)17,214,885 15,670,182
8 Transmission Plant (Estimated)12,564,087 11,778,851
9 Distribution Plant (Estimated)31,201,394 44,464,177
10 Regional Transmission and Market Operation Plant (Estimated)
11 Assigned to - Other (provide details in footnote)1,197,974 (a)1,416,614
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)62,178,340 73,329,824
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)0
15 Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16 Stores Expense Undistributed (Account 163)2,762,521 4,221,832
17
18
19
20 TOTAL Materials and Supplies 96,586,805 95,596,773
FERC FORM No. 1 (REV. 12-05)
Page 227
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: PlantMaterialsAndOperatingSuppliesOther
This amount represents miscellaneous inventory that is not yet assigned to a particular function.
FERC FORM No. 1 (REV. 12-05)
Page 227
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
Transmission Service and Generation Interconnection Study Costs
Line
No.
Description
(a)
Costs Incurred During Period
(b)
Account Charged
(c)
Reimbursements Received During the Period
(d)
Account Credited With
Reimbursement
(e)
1 Transmission Studies
2 IPCL TRANS SIS 88754178 (608)186623 0 186623
3 BPA NETWORK 92112952 19,890 186623 1,700 186623
4 PWX LTF PTP 92117932 0 186623 5,009 186623
5 PWX LTF PTP 92117933 0 186623 7,851 186623
6 PWX LTF PTP 92502052 STUDY 4,635 186623 15,027 186623
7 MCPI LTF PTP 92958045 STUDY 2,722 186623 (2,722)186623
8 MSCG LTF PTP 92838888 STUDY 1,743 186623 (1,743)186623
9 MSCG LTF PTP 92838889 STUDY 1,378 186623 (1,378)186623
10 MSCG LTF PTP 92838891 STUDY 1,437 186623 (1,437)186623
11 PWX LTF PTP 92993105 STUDY 1,662 186623 (1,662)186623
12 PWX LTF PTP 93016533 STUDY 406 186623 (406)186623
13 PAC LTF PTP 93142712 STUDY 9,917 186623 (9,917)186623
14 PAC NETWORK PTP 92946345 STUDY 1,595 186623 (1,595)186623
15 PWX LTF PTP 93468056 STUDY 4,658 186623 (4,658)186623
16 EAGL LTF PTP 93561216 STUDY 325 186623 (325)186623
17 MEAI LTF PTP 94385882 STUDY 985 186623 (985)186623
18 MEAI LTF PTP 94385885 STUDY 960 186623 (960)186623
19 MEAI LTF PTP 94385897 STUDY 639 186623 (639)186623
20 MCPI LTF PTP 94385897 STUDY 772 186623 (772)186623
21 PWX LTF PTP 94688523 STUDY 882 186623 (10,000)186623
22 PWX LTF PTP 94688524 STUDY 574 186623 (10,000)186623
23 BPAP LTF PTP 94946026 STUDY 454 186623 (20,000)186623
24 BPAP LTF PTP 94946039 STUDY 260 186623 0 186623
25 BPAP 91629500 BIENNIAL REASSESSMENT 472 186623 0 186623
26 BPAP 91629850 BIENNIAL REASSESSMENT 472 186623 0 186623
20 Total 56,230 (a)(39,612)
21 Generation Studies
22 CAT CREEK PUMP STORAGE #530 2,602 186623 69,044 186623
23 PRAIRIE CITY SOLAR #556 21,161 186623 (380)186623
24 ARH SOLAR #558 206 186623 87,909 186623
25 BLACK MESA ENERGY #557 19,954 186623 80,853 186623
26 MC6 HYDRO #559 0 186623 7,221 186623
27 BENNETT SOLAR 1 #551 9,342 186623 (100,000)186623
28 BENNETT SOLAR 4 #560 (2,333)186623 0 186623
29 COLEMAN HYDRO #548 3,069 186623 26,931 186623
30 MIDPOINT SOLAR #561 831 186623 59,051 186623
31 MOORE HOLLOW SOLAR #561 14,729 186623 44,786 186623
32 DURKEE SOLAR #546 168 186623 29,428 186623
33 PLEASANT VALLEY SOLAR #568 26,500 186623 (25,694)186623
34 ARCO WIND 950MW #563 7,548 186623 0 186623
35 ARCO SOLAR 950MW #563 (7,511)186623 0 186623
36 MOON CRATER SOLAR #57 16,286 186623 57,345 186623
37 MAGIC VALLEY ENERGY #572 33,151 186623 (59,973)186623
38 OLD OREGON TRAIL 1 #568 5,988 186623 49,214 186623
39 JACOBSON SOLAR #566 0 186623 5,483 186623
40 WEST POINT NRG #576 10,378 186623 17,545 186623
41 ARCO WIND 2 #580 14,954 186623 4,000 186623
42 HIDDEN HOLLOW ENERGY #577 0 186623 1,000 186623
43 MAGIC VALLEY WIND (2) #581 19,520 186623 (57,156)186623
44 PEASANT VALLEY SOLAR (2) #587 12,034 186623 (108,991)186623
45 APPALOOSA WIND & SOLAR #1 400MW 32,779 186623 (60,000)186623
46 APPALOOSA WIND & SOLAR #2 400MW #590 12,306 186623 (2,306)186623
47 FRANKLIN SOLAR #549 15,927 186623 (66,451)186623
48 PIGEON COVE HYDRO- MV90 METER INSALL 0 186623 1,500 186623
49 NORTH POWDER SOLAR #595 335 186623 (335)186623
50 WOOD CREEK RANCH #578 11,243 186623 (50,000)186623
51 PILLAR FALLS HYDRO #601 13,524 186623 (10,000)186623
52 SWAN FALLS #602 100MW 29 186623 (29)186623
FERC FORM No. 1 (NEW. 03-07)
Page 231
53 ARCHER STATION #603 100MW 5,394 186623 (5,394)186623
54 CRIMSON ORCHARD #604 240MW 7,633 186623 (54,003)186623
55 SOUTH BENNETT #605 240MW 6,535 186623 (54,232)186623
56 JACKALOPE 1 #607 300 MW 10,597 186623 (55,130)186623
57 JACKALOPE 2 #608 300 MW 4,050 186623 (53,092)186623
58 JACKALOPE 2 #609 300 MW 3,978 186623 (52,933)186623
59 LANGLEY GULCH EXPANSION II 610 3,974 186623 (3,781)186623
60 OLD OREGON TRAIL PV1 #611 2,809 186623 (2,809)186623
61 OLD OREGON TRAIL PV2 #612 2,429 186623 (2,429)186623
62 OLD OREGON TRAIL PV3 #613 2,431 186623 (51,579)186623
63 SALMON FALLS WIND #614 8,507 186623 (80,000)186623
64 JUNIPER GULCH #617 395 186623 (20,000)186623
65 SALMON FALLS WIND 2 #616 4,108 186623 (70,000)186623
66 FILR ENERGY STORAGE #618 1,463 186623 0 186623
67 HMWY ENERGY STORAGE #619 2,308 186623 0 186623
68 BENNETT MOUNTAIN EXPANSION #620 1,816 186623 0 186623
69 DANSKIN EXPANSION #621 1,912 186623 0 186623
70 OWYHEE PUMPED STORAGE #622 2,209 186623 (10,000)186623
71 MOSBY BUTTE SOLAR #623 7,550 186623 (10,000)186623
72 GEM VALE 1 #624 3,047 186623 (20,000)186623
73 GEM VALE 2 #625 3,047 186623 (20,000)186623
74 MLBA ENERGY STORAGE #627 2,549 186623 0 186623
39 Total 383,461 (b)(565,387)
40 Grand Total 439,691 (604,999)
FERC FORM No. 1 (NEW. 03-07)
Page 231
Transmission Service and Generation Interconnection Study Costs
Line
No.
Description
(a)
Costs Incurred During Period
(b)
Account Charged
(c)
Reimbursements Received During the Period
(d)
Account Credited With
Reimbursement
(e)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: StudyCostsReimbursements
Amounts represent both reimbursements received (credit amounts) and refunds back to the counterparties (debit amounts). Refunds are initiated when studies are complete and the initial deposit exceeds the final expenses.
(b) Concept: StudyCostsReimbursements
FERC FORM No. 1 (NEW. 03-07)
Page 231
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
OTHER REGULATORY ASSETS (Account 182.3)
CREDITS CREDITS
Line
No.
Description and Purpose of Other Regulatory Assets
(a)
Balance at Beginning of Current
Quarter/Year
(b)
Debits
(c)
Written off During
Quarter/Year Account
Charged
(d)
Written off During the Period Amount
(e)
Balance at end of Current
Quarter/Year
(f)
1 Fixed Cost Adjustment (FCA) (182302)38,158,387 35,057,904 1823 38,158,387 35,057,904
2 IPUC Order Pending (Amort period 06/22 thru 05/23)0
3 COVID Incremental Expenses-ID (182303)1,610,800 401 1,149,931 460,869
4 IPUC Order #34718 0
5 Arrearage Management Program-OR (182304)276,473 348,448 1823 276,473 348,448
6 OPUC Order #20-377 0
7 (a)
AOCI Impact of Unfunded Pension Liability 6,561,561 2283 14,501,270 (7,939,709)
8 IPUC Order #30256 (182320)0
9 FCA Calendar Mo Adjustment (182308)1,170,999 1,345,251 2,516,250
10 Prior Year FCA (182309)16,162,399 400 16,162,399 0
11 IPUC Order #34685 (Amort period 06/20 thru 05/21)0
12 Prior Year FCA (182309)38,315,499 400 20,945,430 17,370,069
13 IPUC Order #35056 (Amort period 06/21 thru 05/22)0
14 AOCI Impact of Unfunded Pension Liability 437,908,445 2283 114,957,615 322,950,830
15 IPUC Order #30256 (182320)0
16 Deferred Pension Expense Net of Contributions 26,168,809 48,962,200 1823 38,316,576 36,814,433
17 IPUC Order #30333 (182321)0
18 FAS 109 Unfunded (182322)446,588,083 49,305,762 Multiple 3,595,373 492,298,472
19 Accum Deferred Income Noncurrent 0
20 Idaho Pension Cash - IPUC Order #32248 (182327)174,517,493 23,105,067 197,622,560
21 Amort period 06/11 thru indefinite 0
22 Mark- to Market Short Term (182330)609,571 1,380,140 1,989,711
23 Oregon Pension Expense Capitalized (182339)6,014,090 853,113 4073 195,298 6,671,905
24 OPUC Order #10-064 0
25 Asset Retirement Obligations (182341)19,034,854 3,550,321 22,585,175
26 IPUC Order #29414; OPUC Order #04-585 0
27 RA-Hells Canyon-Baker Co (182360)313,506 313,506
28 IPUC Order #33948 0
29 Oregon Corporate Activity Tax (182355)292,171 281,937 Multiple 170,984 403,124
30 OPUC Order #20-397 0
31 Lidar Surveys-IPUC Order #32426 (182361)43,604 402 43,604 0
32 Amort period 01/12 thru 12/21 0
33 Oregon Community Solar (182378)118,611 51,497 170,108
34 OPUC Order #16-410 0
35 Intervenor Funding-Idaho (182387)281,287 6,776 288,063
36 Multiple IPUC Orders 0
37 RA-CONTRA-DEF INC TAX (182389)241,040,365 1,204,793 282 13,267,678 228,977,480
38 Langley Revenue Accrual (182398)1,422,366 36,880 4073 369,171 1,090,075
39 OPUC Order #12-226 0
40 RA-OR LANGLEY REV INT RES (182399)(223,306)58,254 (165,052)
41 Siemens Long Term Deferred Rate Base (182410)9,475,468 4073 431,488 9,043,980
42 IPUC Order #33420 (Amort period 01/16 thru 12/43)0
43 Siemens Long Term Deferred Rate Based (182411)14,139,304 4073 643,866 13,495,438
44 IPUC Order #33420 (Amort period 01/16 thru 12/43)0
45 Siemens Long Term Deferred Rate Base (182412)389,789 29,734 4073 44,047 375,476
46 OPUC Order #15-387 (Amort period 01/16 thru 12/36)0
47 Siemens Long Term Deferred Rate Based (182413)589,737 4073 39,316 550,421
48 OPUC Order #15-387 (Amort period 01/16 thru 12/36)0
49 Siemens Long Term Interest Reserve (182414)(163,146)4190 29,734 (192,880)
50 Valmy O&M ID (182432)1,107,639 11,072,090 400 10,564,033 1,615,696
51 IPUC Order #33771 0
52 Valmy Acctg Adj ID (182435)101,421,114 400 4,895,133 96,525,981
53 IPUC Order #33771 0
54 Valmy Decomm Oregon (182436)562,796 1,016,080 400 1,168,033 410,843
55 OPUC Order #17-235 (Amort period 06/17 thru 12/25)0
56 (b)
Idaho DSM Rider 12,230,374 28,053,942 400 33,346,611 6,937,705
57 IPUC Order#28661 0
FERC FORM No. 1 (REV. 02-04)
Page 232
58 (c)
Oregon DSM Rider 995,040 1,786,261 400 2,097,318 683,983
59 OPUC Advice #05-03 0
60 COVID Incremental Expenses-OR (182305)0 282,100 401 67,537 214,563
61 OPUC Order #20-377 0
62 PCA Deferral Idaho-Prior Year (182324)0 23,535,995 Multiple 22,216,769 1,319,226
63 IPUC Order #35054 (Amort period 06/21 thru 05/22)0
64 PCA Deferral Idaho-Current Year (multiple 182 accounts)0 44,367,930 Multiple 11,737,475 32,630,455
65 IPUC Order Pending (Amort period 06/22 thru 05/23)0
66 Mark-to-Market Long Term (182333)15,462 3,742,090 3,757,552
67 (d)
ID Valmy Collections (182430)(6,301)400 694,529 (700,830)
68 IPUC Order #33771 0
69 Wildfire Mitigation-ID (182310)0 6,075,024 6,075,024
70 IPUC Order #35077 0
71 Cloud Computing (182315)0 1,509,490 4073 100,633 1,408,857
72 IPUC Order #34707 0
73 (e)
Oregon Green Tags (254415)0 0 1823 295,256 (295,256)
74 OPUC Advice #11-086 0
75 Minor items (5)66,865 96,917 Multiple 96,716 67,066
44 TOTAL 1,558,894,709 325,431,495 350,578,683 1,533,747,521
FERC FORM No. 1 (REV. 02-04)
Page 232
OTHER REGULATORY ASSETS (Account 182.3)
CREDITS CREDITS
Line
No.
Description and Purpose of Other Regulatory Assets
(a)
Balance at Beginning of Current
Quarter/Year
(b)
Debits
(c)
Written off During
Quarter/Year Account
Charged
(d)
Written off During the Period Amount
(e)
Balance at end of Current
Quarter/Year
(f)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Regulatory Asset is in a credit position, but is netted with the other Postretirement regulatory accounts for presentation as a net Regulatory Asset on the year-end financial statements.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
During 2021, this balance was reclassed from a Regulatory Liability to a Regulatory Asset for financial statement presentation.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
During 2021, this balance was reclassed from a Regulatory Liability to a Regulatory Asset for financial statement presentation.
(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Regulatory asset is in a credit position, but it is netted against other Valmy related regulatory asset accounts for a net Regulatory Asset on the year-end financial statements.
(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
This regulatory liability account is netted against other power cost adjustment recovery accounts, presented as a net Regulatory Asset on the year-end financial statements.
FERC FORM No. 1 (REV. 02-04)
Page 232
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
CREDITS CREDITS
Line
No.
Description of Miscellaneous Deferred Debits
(a)
Balance at Beginning of Year
(b)
Debits
(c)
Credits Account
Charged
(d)
Credits Amount
(e)
Balance at End of Year
(f)
1 Prepaid Credit Facility 186025 931,418 1,819,125 Mulitplle 1,862,558 887,985
2 Amortization period 12/19-12/24
3 Prepaid Services (LT) 186052 3,661,806 201,454 Multiple 801,412 3,061,848
4 Amortization periods - multiple
5 Workers Compensation 186121 909,224 25,493 934,717
6 Prepaid ROW (LT) 186160 530,855 401 43,901 486,954
7 Amortization periods - multiple
8 Prepaid Services (LT) 186255
9 Amortization periods - multiple
10 CARB Inventory 186650 1,404,931 589,500 242 1,499,484 494,947
11 Coal Royalties/Fly Ash 186709 820,176 241,696 151 100,544 961,328
12 Stable Value Life Inv 186719 52,326,233 4,910,931 57,237,164
13 Security Plan 186720 5,901,357 83,700 4262 197,420 5,787,637
14 Net Insurance Asset
15 Retiree Medical-COLI 186726 4,154,165 167,251 4262 3,401 4,318,015
16 American Falls Water Rts 186727 4,254,870 401 1,042,009 3,212,861
17 Amortization period 01/06-02/25
18 American Falls Bond Refi 186770 199,997 401 47,999 151,998
19 Amortization period 12/09-02/25
20 Regulatory Reserves 186800 (1,887,272)Multiple 228,762 (2,116,034)
21 Minor Items (5)95,126 908,065 Multiple 985,661 17,530
47 Miscellaneous Work in Progress
48 Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49 TOTAL 73,302,886 75,436,950
FERC FORM No. 1 (ED. 12-94)
Page 233
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Line No.Description and Location
(a)
Balance at Beginning of Year
(b)
Balance at End of Year
(c)
1 Electric
2 Construction Advances 1,325,912 1,753,689
3 Postretirement Benefits 419,012 500,537
4 USBR-American Falls O&M Costs Settlement 46,482 118,624
5 Non-VEBA Pension and Benefits Non-VEBA Pension and Benefits (629,527)(699,431)
6 Executive Deferred Compensation 23,045 52,084
7 Stock Based Compensation 2,921,158 2,956,484
8 Pension Expense-Oregon 3,758,893 4,173,591
9 Bridger Revenue Deferral 806,746 960,590
10 Asset Retirement Obligation (ARO)1,563,709 1,578,325
11 Incentive Deferral-Profit Sharing-Not in Rates 3,182,560 3,705,325
12 OR Reconnect Fees Adv 2,422 2,841
13 Tax Reform Regulatory Stipulation 4,496,944 6,460,884
14 Employer FICA Tax Deferral-CARES Act 2,251,257 1,126,180
15 Rate Case Disallowance 1,115,685 1,039,418
16 Unrealized Loss on Investments Unrealized Loss on Investments (128)1,287
17 Prov for Rate Refund-HC Relicensing (AFUDC)43,524,951 48,318,135
18 Revenue Sharing 146,402
19 VEBA-Post Retirement Benefits 9,757,342 11,242,321
20 Deferred Idaho ITC 23,870,142 28,267,325
7 Other (a)225,441,615 192,659,208
8 TOTAL Electric (Enter Total of lines 2 thru 7)323,878,220 304,363,819
9 Gas
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15)0 0
17.1 (b)
Other Non Electric (See footnote)19,632,237 20,324,309
17 Other (Specify)
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)343,510,457 324,688,128
FERC FORM NO. 1 (ED. 12-88)
Page 234
Notes
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: AccumulatedDeferredIncomeTaxes
Line No.: 7
Pension-FAS 158 112,806,488 83,910,187
Regulatory Liability-FAS 109 95,883,179 96,879,711
Minimum Pension Liability 15,063,002 13,912,991
Postretirement Plan-FAS 158 1,688,946 (2,043,681)
Total Other 225,441,615 192,659,208
(b) Concept: DescriptionOfAccumulatedDeferredIncomeTax
Line No.: 17
Senior Management Security Plan 19,632,237 20,324,309
Total Non Electric 19,632,237 20,324,309
FERC FORM NO. 1 (ED. 12-88)
Page 234
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
CAPITAL STOCKS (Account 201 and 204)
Line
No.
Class and Series of Stock and Name of Stock Series
(a)
Number of Shares Authorized by
Charter
(b)
Par or Stated Value per Share
(c)
Call Price at End of Year
(d)
Outstanding per Bal. Sheet (Total
amount outstanding without
reduction for amounts held by
respondent) Shares
(e)
Outstanding per Bal. Sheet
(Total amount outstanding
without reduction for amounts
held by respondent) Amount
(f)
1 Common Stock (Account 201)
2 Account 201
3 Common Stock all of which is held by 50,000,000 2.5 39,150,812 97,877,030
4 IdaCorp, Inc. and not traded
5 Account 204 - None
14 Total 50,000,000 39,150,812 97,877,030
15 Preferred Stock (Account 204)
16
17
18
19 Total 0
1 Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5 Total
FERC FORM NO. 1 (ED. 12-91)
Page 250-251
CAPITAL STOCKS (Account 201 and 204)
Line
No.
Held by Respondent As Reacquired Stock (Acct 217)
Shares
(g)
Held by Respondent As Reacquired Stock (Acct 217) Cost
(h)
Held by Respondent In Sinking and Other Funds Shares
(i)
Held by Respondent In Sinking and Other Funds Amount
(j)
1
2
3
4
5
14
15
16
17
18
19
1
2
3
4
5
FERC FORM NO. 1 (ED. 12-91)
Page 250-251
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2022-04-15
Year/Period of Report
End of: 2021/ Q4
Other Paid-in Capital
Line No.Item
(a)
Amount
(b)
1 Donations Received from Stockholders (Account 208)
2 Beginning Balance Amount 0
3 Increases (Decreases) from Sales of Donations Received from Stockholders
4 Ending Balance Amount 0
5 Reduction in Par or Stated Value of Capital Stock (Account 209)
6 Beginning Balance Amount 0
7 Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8 Ending Balance Amount 0
9 Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10 Beginning Balance Amount 0
11 Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12 Ending Balance Amount 0
13 Miscellaneous Paid-In Capital (Account 211)
14 Beginning Balance Amount 0
15 Increases (Decreases) Due to Miscellaneous Paid-In Capital
16 Ending Balance Amount 0
17 Historical Data - Other Paid in Capital
18 Beginning Balance Amount 0
19 Increases (Decreases) in Other Paid-In Capital
20 Ending Balance Amount 0
40 Total 0
FERC FORM No. 1 (ED. 12-87)
Page 253
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
CAPITAL STOCK EXPENSE (Account 214)
Line No.Class and Series of Stock
(a)
Balance at End of Year
(b)
1 Common Stock 2,096,925
22 TOTAL 2,096,925
FERC FORM No. 1 (ED. 12-87)
Page 254b
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Line
No.
Class and Series of Obligation, Coupon Rate (For new
issue, give commission Authorization numbers and dates)
(a)
Related Account
Number
(b)
Principal Amount of Debt Issued
(c)
Total Expense, Premium or
Discount
(d)
Total Expense
(e)
Total Premium
(f)
Total
Discount
(g)
1 Bonds (Account 221)
2 4.00% Series due 2043 221101 75,000,000 742,017 194,250
3 2.50% Series due 2023 221102 75,000,000 648,267 374,250
4 3.65% Series Due 2045 221107 250,000,000 2,559,510 1,715,000
5 (a)
4.20% Series Due 2048 221110 450,000,000 4,629,516 (31,654,900)814,000
6 5.875% Series due 2034 221116 55,000,000 585,759 748,000
7 6.00% Series due 2032 221133 100,000,000 1,191,216 544,000
8 5.30% Series Due 2035 221134 60,000,000 3,849,739 408,600
9 5.50% Series due 2033 221135 70,000,000 728,701 36,400
10 6.30% Series due 2037 221141 140,000,000 1,500,031 278,600
11 6.25% Series due 2037 221142 100,000,000 1,227,490 268,000
12 5.50% Series due 2034 221145 50,000,000 524,419 383,500
13 4.85% Series Due 2040 221146 100,000,000 1,284,871 170,000
14 4.30% Series Due 2042 221147 75,000,000 802,240 49,500
15 4.05% Series Due 2046 221148 120,000,000 1,311,383 309,600
16 1.90% Series Due 2030 221149 80,000,000 980,949 328,000
17 Port of Morrow Variable due 2027 221311 4,360,000 189,597
18 Humboldt 1.45 % due 2024 221325 49,800,000 396,278
19 Sweetwater 1.7% due 2026 221335 116,300,000 90,898
20 Subtotal 1,970,460,000 23,242,881 (31,654,900)6,621,700
21 Reacquired Bonds (Account 222)
22
23
24
25 Subtotal
26 Advances from Associated Companies (Account 223)
27
28
29
30 Subtotal
31 Other Long Term Debt (Account 224)
32 Bond Guarantee - American Falls 224200 19,885,000
33 Subtotal 19,885,000 0 0 0
33 TOTAL 1,990,345,000
FERC FORM No. 1 (ED. 12-96)
Page 256-257
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Line
No.
Nominal Date of Issue
(h)
Date of Maturity
(i)
AMORTIZATION PERIOD Date From
(j)
AMORTIZATION PERIOD Date To
(k)
Outstanding (Total amount outstanding
without reduction for amounts held by
respondent)
(l)
Interest for Year Amount
(m)
1
2 04/07/2013 03/31/2043 04/07/2013 03/31/2043 75,000,000 3,000,000
3 04/07/2013 03/31/2023 04/07/2013 03/31/2023 75,000,000 1,875,000
4 03/05/2015 02/28/2045 03/05/2015 02/28/2045 250,000,000 9,125,000
5 03/15/2018 02/29/2048 03/15/2018 02/29/2048 450,000,000 18,900,000
6 08/15/2004 08/14/2034 08/15/2004 08/14/2034 55,000,000 3,231,250
7 11/14/2002 11/14/2032 11/14/2002 11/14/2032 100,000,000 6,000,000
8 08/25/2005 08/14/2035 08/25/2005 08/14/2035 60,000,000 3,180,000
9 05/12/2003 03/31/2033 05/12/2003 03/31/2033 70,000,000 3,850,000
10 06/21/2007 06/14/2037 06/21/2007 06/14/2037 140,000,000 8,820,000
11 10/17/2007 10/14/2037 10/17/2007 10/14/2037 100,000,000 6,250,000
12 03/25/2004 03/14/2034 03/25/2004 03/14/2034 50,000,000 2,750,000
13 08/29/2010 08/14/2040 08/29/2010 08/14/2040 100,000,000 4,850,000
14 04/12/2012 03/31/2042 04/12/2012 03/31/2042 75,000,000 3,225,000
15 03/09/2016 02/28/2046 03/09/2016 02/28/2046 120,000,000 4,860,000
16 06/21/2020 06/14/2030 06/21/2020 06/14/2030 80,000,000 1,520,000
17 05/16/2000 01/31/2027 05/16/2000 01/31/2027 4,360,000 9,490
18 08/20/2019 11/30/2024 08/20/2019 11/30/2024 49,800,000 722,100
19 08/20/2019 07/14/2026 08/20/2019 07/14/2026 116,300,000 1,977,100
20 1,970,460,000 84,144,940
21
22
23
24
25 0
26
27
28
29
30
31
32 04/26/2000 02/01/2025 19,885,000
33 19,885,000 0
33 1,990,345,000 84,144,940
FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: ClassAndSeriesOfObligationCouponRateDescription
Page 256 Row 4: Additional $230 million of 4.20% bonds due 3/1/2048 issued on 4/3/2020 with a premium of $31,654,900 bringing total 4.20% series outstanding to $450 million.
FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Line No.Particulars (Details)
(a)
Amount
(b)
1 Net Income for the Year (Page 117)243,225,299
2 Reconciling Items for the Year
3
4 Taxable Income Not Reported on Books
5 CONSTRUCTION ADVANCES 2,641,589
6 AVOIDED COST 5,130,358
7 CIAC - TAXABLE - ACCT 107 23,648,037
8 ENGINEERING FEES - TAXABLE - ACCT 107 920,481
9 VALMY SETTLEMENT ADJUSTMENT 6,436,592
9 Deductions Recorded on Books Not Deducted for Return
10 BAD DEBT EXPENSE 247,787
11 GAIN/LOSS ON REACQUIRED DEBT 273,234
12 VACATION ACCRUAL 1,760,642
13 INJURIES AND DAMAGES 1,269,257
14 COVID DEFERRAL ORD 34718 1,306,718
15 STOCK BASED COMPENSATION 861,895
16 FIXED COST ADJUSTMENT 547,562
17 PENSION EXPENSE - OREGON 1,611,102
18 ASSET RETIREMENT OBLIGATION (ARO)56,783
19 INCENTIVE DEFERRAL-PROFIT SHARING-NOT IN RATES 2,267,877
20 VALMY DEPRECIATION ADJUSTMENT 4,129,844
21 TAX REFORM REGULATORY STIPULATION 7,629,913
22 NON-DEDUCTIBLE POLITICAL EXPENSES 804,882
23 SMSP - NET 2,688,704
24 PROV FOR RATE REFUND - HC RELICENSING (AFUDC)18,621,537
25 REVENUE SHARING 568,771
26 VEBA - POST RETIREMENT BENEFITS 5,769,149
27 DEPR TIMING DIFF - OPERATING - FEDERAL 107,050,265
28 CONSERVATION EXPENSES 5,725,329
29 GAIN/LOSS ON REACQUIRED DEBT 2,665,480
30 IPCO-162(m) $1M THRESHOLD 4,210,266
31 VALMY1 BOOK BASIS ADJUSTMENT 3,081,950
32 TOTAL FEDERAL AND STATE TAXES DEDUCTED ON BOOKS 37,043,766
14 Income Recorded on Books Not Included in Return
15 BOARDMAN DECOMMISSION 56,994
16 SMSP - INSURANCE COSTS 4,994,626
17 REVERSE EQUITY EARNINGS OF SUBSIDIARIES 8,991,347
18 ALLOWANCE FOR OFUDC 31,537,344
19 ALLOWANCE FOR BFUDC 11,992,630
20 SMSP - INSURANCE PROCEEDS 44,893
19 Deductions on Return Not Charged Against Book Income
20 263A CAPITALIZED OVERHEADS 39,000,000
21 PENSION EXPENSE 24,802,227
22 PCA EXPENSE DEFERRAL 35,022,109
23 AMORTIZATION OF ACCOUNT 181 298,447
24 INCENTIVE DEFERRAL-CRI & RELIABILITY-INCLUDED IN RATES 2,342,156
25 EMPLOYER FICA TAX DEFERRAL-CARES ACT 4,370,929
26 STOCK BASED COMP - STOCK 115,427
27 REMOVAL COSTS 15,723,353
28 SOFTWARE - LABOR COSTS DEDUCTED - ACCT 107 5,086,000
29 RELICENSING - LABOR COSTS DEDUCTED - ACCT 107 2,577,000
30 REPAIRS DEDUCTION 83,000,000
31 PREPAID INSURANCE & OTHER EXPENSES 3,532,535
32 STOCK BASED COMP - DIVIDENDS 658,494
33 OR CAT 262,395
34 INCOME TAX DEDUCTED ON FEDERAL RETURN 12,755,506
27 Federal Tax Net Income 205,030,654
28 Show Computation of Tax:
29 Tentative Federal Tax @ 21%43,056,438
FERC FORM NO. 1 (ED. 12-96)
Page 261
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
BALANCE
AT
BEGINNING
OF YEAR
BALANCE
AT
BEGINNING
OF YEAR
Line
No.
Kind of Tax (See Instruction 5)
(a)
Type of Tax
(b)
State
(c)
Tax Year
(d)
Taxes
Accrued
(Account
236)
(e)
Prepaid
Taxes
(Include in
Account
165)
(f)
1 Federal Income Tax (3,738,834)
2 State Income Tax Idaho (1,247,810)
3 State Income Tax Oregon 91,983
4 Other (a)
Income Tax Other 182,622 0
5 Subtotal Income Tax (4,712,039)0
6 Federal (b)
Other Taxes 8,652,508 0
7 Other (c)
Other Taxes Other (18,825)0
8 Subtotal Other Taxes 8,633,683 0
9 Federal Unemployment Tax (2,016)0
10 State Unemployment Tax Idaho (2,159)0
11 State Unemployment Tax Oregon 0 0
12 Subtotal Unemployment Tax (4,175)0
13 State Property Tax Idaho 9,397,066 0
14 State Property Tax Oregon 0 1,988,443
15 State Property Tax Montana 233,261 0
16 State Property Tax Nevada 0 267,925
17 State Property Tax Wyoming 715,344 0
18 State Property Tax Washington 8,000 0
19 Subtotal Property Tax 10,353,671 2,256,368
20 State (d)
Other State Tax Idaho 17,179 0
21 State (e)
Other State Tax Idaho 84,507 0
22 State (f)
Other State Tax Idaho 0 0
23 State (g)
Other State Tax Oregon 0 1,001
24 State (h)
Other State Tax Oregon 0 0
25 Subtotal Other State Tax 101,686 1,001
26 State (i)
Other License And Fees Tax Idaho 0 0
27 State (j)
Other License And Fees Tax Wyoming 0 0
28 Subtotal Other License And Fees Tax 0 0
29 Other Payroll Tax Other 0 0
30 Subtotal Payroll Tax 0 0
31 State Franchise Tax Oregon 195,414 0
32 Subtotal Franchise Tax 195,414 0
40 TOTAL 14,568,240 2,257,369
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
BALANCE AT END OF YEAR BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED
Line
No.
Taxes Charged During Year
(g)
Taxes Paid During Year
(h)
Adjustments
(i)
Taxes Accrued (Account 236)
(j)
Prepaid Taxes (Included in Account
165)
(k)
Electric (Account 408.1, 409.1)
(l)
1 34,196,957 42,521,315 (12,063,192)35,047,688
2 12,119,165 14,682,919 (3,811,564)12,303,426
3 1,025,366 1,065,391 51,958 940,300
4 50,718 9,734 223,606 55,230
5 47,392,206 58,279,359 0 0 48,346,644
6 16,901,128 21,282,394 0 4,271,242 0 16,901,128
7 0 (17,791)(l)11,760 10,726 0 0
8 16,901,128 21,264,603 11,760 0 16,901,128
9 91,289 91,247 0 (1,974)0 91,289
10 177,697 177,827 0 (2,289)0 177,697
11 38,864 38,864 0 0 0 38,864
12 307,850 307,938 0 0 307,850
13 19,547,027 20,376,854 0 8,567,239 0 19,538,790
14 4,569,444 5,160,142 0 2 2,579,143 4,426,709
15 443,263 455,181 0 221,343 0 443,263
16 442,913 349,935 0 0 174,947 442,913
17 1,316,750 1,373,720 0 658,374 0 1,316,750
18 5,378 6,689 0 6,689 0 5,378
19 26,324,775 27,722,521 0 2,754,090 26,173,803
20 22,176 28,267 0 11,088 0
21 1,310,347 1,286,465 0 108,389 0 1,310,347
22 2,402,308 2,402,308 0 0 0 2,402,308
23 2,024 2,045 0 0 1,022
24 235,244 292,243 28,500 1 28,500 235,244
25 3,972,099 4,011,328 28,500 29,522 3,947,899
26 150 150 0 0 0 150
27 3,859 3,859 0 0 0 3,859
28 4,009 4,009 0 0 4,009
29 (k)(17,208,978)0 17,208,978 0 0 (17,208,978)
30 (17,208,978)0 17,208,978 0 (17,208,978)
31 821,549 826,828 0 190,135 0 821,549
32 821,549 826,828 0 0 821,549
40 78,514,638 112,416,586 17,249,238 (1,558,227)2,783,612 79,293,904
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
DISTRIBUTION OF TAXES CHARGED DISTRIBUTION OF TAXES CHARGED DISTRIBUTION OF TAXES CHARGED
Line No.Extraordinary Items (Account 409.3)
(m)
Adjustment to Ret. Earnings (Account 439)
(n)
Other
(o)
1 (m)(850,731)
2 (n)(184,261)
3 (o)85,066
4 (p)(4,512)
5 0 0 (954,438)
6 0
7 0
8 0 0 0
9 0
10 0
11 0
12 0 0 0
13 (q)8,238
14 142,734
15 0
16 0
17 0
18 0
19 0 0 150,972
20 22,176
21 0
22 0
23 2,024
24 0
25 0 0 24,200
26 0
27 0
28 0 0 0
29 0
30 0 0 0
31 0
32 0 0 0
40 0 (779,266)
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: TypeOfTax
Page 262 Col B Line 22: Other States Income
(b) Concept: TypeOfTax
Page 262 Col B Line 3: Social Security (FOAB)
(c) Concept: TypeOfTax
Page 262 Col B Line 23: Canada GST Tax
(d) Concept: TypeOfTax
Page 262 Col B Line 7: Non-Operating
(e) Concept: TypeOfTax
Page 262 Col B Line 8: kWh
(f) Concept: TypeOfTax
Page 262 Col B Line 9: Regulatory Commission
(g) Concept: TypeOfTax
Page 262 Col B Line 14: Non-Operating
(h) Concept: TypeOfTax
Page 262 Col B Line 15: Regulatory Commission
(i) Concept: TypeOfTax
Page 262 Col B Line 10: Business License- Sho-Ban
(j) Concept: TypeOfTax
Page 262 Col B Line 20: Corporate License
(k) Concept: TaxesCharged
Page 262 Col G Line 24: This amount is offset to lines 2, 3, 5, and 12. Each month employer paid taxes flow into various 408.1 accounts. In that same month these amounts are offset with a different 408.1 account. These payroll taxes are then allocated back to the
balance sheet and O&M accounts based on current month labor charges.
(l) Concept: TaxAdjustments
Page 262 Col I Line 23: Canada GST accrual is an adjustment because the offset account is not a 600 expense account.
(m) Concept: TaxesIncurredOther
Page 262 Col O Line 1:
Account 409.2 -644,711
Account 426.5 -134,212
Account 409.1 -71,808
--------------------------------------------
Total -850,731
(n) Concept: TaxesIncurredOther
Page 262 Col O Line 4:
Account 409.2 -184,261
(o) Concept: TaxesIncurredOther
Page 262 Col O Line 11:
Account 236.4 2,773
Account 409.2 -9,669
Account 182.3 91,962
----------------------------------------------
Total 85,066
(p) Concept: TaxesIncurredOther
Page 262 Col O Line 22:
Account 409.2 -2,663
Account 411.1 -1,849
---------------------------------------------
Total -4,512
(q) Concept: TaxesIncurredOther
Page 262 Col O Line 6:
Account 107 8,238
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Deferred for Year Deferred for Year Allocations to Current
Year's Income Allocations to Current Year's Income
Line
No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Account No.
(c)
Amount
(d)
Account No.
(e)
Amount
(f)
1 Electric Utility
2 0.03
3 0.1 10,862,253 411.401 959,741
4 0.04 187,618 411.401 25,023
5 0.07
6 Other - Federal 15,667,208 9,132,425 344,615
7 Other - State 70,909,690 411.402 5,566,055 411.402 1,536,204
8 TOTAL Electric (Enter Total of lines 2 thru 7)97,626,769 14,698,480 2,865,583
9 Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10 .3 14,647,831 411.401 9,132,425 411.401 322,346
11 0.11 1,019,377 411.401 22,269
12 0.11 1,019,377 411.401 22,269
47 OTHER TOTAL 15,667,208 9,132,425 344,615
48 GRAND TOTAL 97,626,769
FERC FORM NO. 1 (ED. 12-89)
Page 266-267
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Line
No.
Adjustments
(g)
Balance at End of Year
(h)
Average Period of Allocation to Income
(i)
ADJUSTMENT EXPLANATION
(j)
1
2
3 9,902,512 11.3179
4 162,595 7.4982
5
6 0 24,455,018 45.4413
7 74,939,541 46.159
8 0 109,459,666
9
10 23,457,910 45.4413
11 997,108 45.77
12 45.7749
47 0 24,455,018
48 109,459,666
FERC FORM NO. 1 (ED. 12-89)
Page 266-267
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
OTHER DEFERRED CREDITS (Account 253)
DEBITS DEBITS
Line
No.
Description and Other Deferred Credits
(a)
Balance at Beginning of Year
(b)
Contra Account
(c)
Amount
(d)
Credits
(e)
Balance at End of Year
(f)
1 PTP Transmission Deposits 253201 3,123,160 131 3,193,213 3,746,714 3,676,661
2 FTV Dark Fiber Rental 253202 466,666 400 400,000 66,666
3 Amortization period 03/98-02/23 0
4 Cogen Deposits 253350 0 147,000 147,000
5 Sho-Ban Scholarships 253480 112,500 242 15,000 97,500
6 Amortization period 01/05-12/27 0
7 Operations Accruals 253550 665,695 131 367,574 298,121
8 Postretirement Benefits 253960 1,944,587 401 405,930 1,538,657
9 Directors Deferred Compensation 3,336,724 131 311,500 205,341 3,230,565
10 253970-253999 0
47 TOTAL 9,649,332 4,693,217 4,099,055 9,055,170
FERC FORM NO. 1 (ED. 12-94)
Page 269
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR
Line
No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account
411.2
(f)
1 Account 282
2 Electric 278,238,885 4,568,210 23,978,840 0 0
3 Gas
4 Other (Specify)
5 Total (Total of lines 2 thru 4)(a)278,238,885 4,568,210 23,978,840 0 0
6 Non-Operating Property
7 Other - Regulatory Asset for Income Taxes 687,628,448
8 Like Kind Exchange - Reclass Non-Rate Base 4,744,329
9 TOTAL Account 282 (Total of Lines 5 thru 8)970,611,662 4,568,210 23,978,840 0 0
10 Classification of TOTAL
11 Federal Income Tax 775,208,130 4,518,723 23,847,695
12 State Income Tax 195,403,532 49,487 131,145
13 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS
Debits Debits Credits Credits
Line
No.
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1
2 0 282/254 9,179,597 268,007,852
3 0
4 0
5 0 9,179,597 268,007,852
6 0
7 0 182 33,647,504 721,275,952
8 282 221,698 4,522,631
9 221,698 42,827,101 993,806,435
10
11 0 182/254 34,952,194 790,831,352
12 182 7,653,210 202,975,084
13 0
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty
Page 274 Line5:
2021 Changes during Year Adjustments Credits 2021
Beginning DR to CR to Acct.Ending
Line Account Balance 410.1 411.1 debited Amount Balance
No.(a)b c d i j k
Line 2:Depreciation Timing Diff-Operating 454,784,844.12 4,475,142.13 18,819,451.00 0.00 440,440,535.25
Like Kind Exchange - Reclass Non-Rate Base (4,744,329.00)0.00 0.00 282111 221,698.00 (4,522,631.00)
Excess Deferred Tax on Depreciation (Reg Liab)(178,996,575.28)0.00 0.00 254967 8,957,898.58 (170,038,676.70)
4013 CIAC-Taxable-Acct 107 (7,042,042.77)251,251.14 4,966,087.77 (11,756,879.40)
4021 Engineering Fees-Taxable-Acct 107 (729,894.27)0.00 193,301.11 (923,195.38)
8059 Software-Labor Costs Deducted-Acct 107 1,995,721.35 (534,415.56)0.00 1,461,305.79
8072 Intangible-Labor Costs Deducted-Acct 107 12,971,160.93 376,232.64 0.00 13,347,393.57
TOTAL Line 5 278,238,885.08 4,568,210.35 23,978,839.88 9,179,596.58 268,007,852.13
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR
Line
No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account
411.2
(f)
1 Account 283
2 Electric
3 Other Electric (a)94,704,840 16,019,183 5,047,785
4 Other (b)114,495,434
9 TOTAL Electric (Total of lines 3 thru 8)209,200,274 16,019,183 5,047,785 0 0
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 TOTAL Other (c)55,151 103,913
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)209,255,425 16,123,096 5,047,785 0 0
20 Classification of TOTAL
21 Federal Income Tax 160,495,467 12,364,799 3,865,627
22 State Income Tax 48,759,958 3,758,297 1,182,158
23 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96)
Page 276-277
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS
Debits Debits Credits Credits
Line
No.
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1
2
3 105,676,238
4 190 (32,628,927)81,866,507
9 0 (32,628,927)187,542,745
10
11
12
13
14
15
16
17
18 159,064
19 0 (32,628,927)187,701,809
20
21 190 (25,023,117)143,971,522
22 190 (7,605,810)43,730,287
23
NOTES
FERC FORM NO. 1 (ED. 12-96)
Page 276-277
FOOTNOTE DATA
(a) Concept: AccumulatedDeferredIncomeTaxesOther
Page 276 Line 3:
2021 Changes during Year 2021
Beginning DR to CR to Ending
Line Account Balance 410.1 411.1 Balance
No.(a)b c d k
Line 3:
4024 Renewable Energy Certificates (REC) Sales 921,731.90 91,356.15 0.00 1,013,088.05
4501 Royalty Income 224,438.40 0.00 13,325.08 211,113.32
5008 Gain/Loss on Reacquired Debt 352,830.29 0.00 70,330.42 282,499.87
5023 Pension Expense 49,903,278.79 6,384,093.23 0.00 56,287,372.02
5035 PCA Expense 0.00 9,014,690.86 0.00 9,014,690.86
5040 Covid Deferral 0.00 0.00 336,349.21 (336,349.21)
5057 Intervenor Funding Orders 57,308.81 23,458.42 0.00 80,767.23
5058 Fixed Cost Adjustment 14,283,585.44 0.00 140,942.46 14,142,642.98
5060 Oregon PCAM 3,969.90 0.00 0.00 3,969.90
5062 2011 LIDAR Surveys Deferral 22,447.58 0.00 11,223.94 11,223.64
5066 Boardman Decommission (337,053.46)14,670.25 0.00 (322,383.21)
5074 Valmy Settlement Adjustment 6,627,115.13 0.00 1,656,778.78 4,970,336.35
5075 EIM Deferral 9,722.51 0.00 7,165.50 2,557.01
5077 Valmy Depreciation Adjustment 19,137,573.66 0.00 1,328,777.04 17,808,796.62
5079 Community Solar Deferral 8,689.82 21,840.65 0.00 30,530.47
7013 Langley Revenue Accrual (0.26)308,638.30 0.00 308,638.04
8020 Conservation Expenses 3,205,538.88 0.00 1,473,699.68 1,731,839.20
8081 Siemens LTP Contract 93,275.60 17,213.63 0.00 110,489.23
8082 Prepaid Credit Facility 122,596.03 0.00 24,934.85 97,661.18
8083 Siemens OR DRB Interest Reserve (34,066.14)0.00 7,927.66 (41,993.80)
8704 Boardman Removal Costs 26,651.72 136,931.39 0.00 163,583.11
8706 OR Annual Reg Exp 0.00 6,290.60 0.00 6,290.60
N/A Oregon CAT Deferral 75,205.00 0.00 (23,670.00)98,875.00
TOTAL Line 3 94,704,839.60 16,019,183.48 5,047,784.62 105,676,238.46
(b) Concept: AccumulatedDeferredIncomeTaxesOther
Page 276 Line 8:
2021 Adjustments Credits 2021
Beginning Acct.Ending
Line Account Balance debited Amount Balance
No.(a)b i j k
Line 8:Pension-FAS 158 112,806,487.68 190 (28,896,300.21)83,910,187.47
Postretirement Plan-FAS 158 1,688,945.92 190 (3,732,627.11)(2,043,681.19)
TOTAL Line 8 114,495,433.60 (32,628,927.32)81,866,506.28
(c) Concept: AccumulatedDeferredIncomeTaxesOther
Page 276 Line 18:
2021 Changes during Year 2021
Beginning DR to Ending
Line Account Balance 410.1 Balance
No.(a)b c k
Line 18:
5503 EDC-Unrealized Gain/Loss From Rabbit Trust 1,692.41 10,226.50 11,918.91
5517 SMSP-Unrealized Gain/Loss From Rabbi Trust 53,209.47 93,678.16 146,887.63
8504 Oregon Non-Op Prop Tax Adj 250.45 7.21 257.66
TOTAL Line 18 55,152.33 103,911.87 159,064.20
FERC FORM NO. 1 (ED. 12-96)
Page 276-277
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
OTHER REGULATORY LIABILITIES (Account 254)
DEBITS DEBITS
Line
No.
Description and Purpose of Other Regulatory Liabilities
(a)
Balance at Beginning of Current
Quarter/Year
(b)
Account Credited
(c)
Amount
(d)
Credits
(e)
Balance at End of Current
Quarter/Year
(f)
1 Market to Market Short Term (254001)1,995,126 5,695,903 7,691,029
2 IPUC Order #28661 0
3 Oregon Solar Rider (254005)145,297 401 20,862 66,363 190,798
4 OPUC Order #10-198 0
5 BPA Credit Residential Idaho (254401)3,444,951 142 20,782,744 18,473,357 1,135,564
6 OPUC Advice #15-13 0
7 BPA Credit Residential Oregon (254402)161,628 142 691,043 669,445 140,030
8 OPUC Advice #15-11 0
9 BPA Credit Farm Idaho (254403)740,354 142 3,297,887 2,857,713 300,180
10 OPUC Advice #15-13 0
11 BPA Credit Farm Oregon (254404)107,944 142 123,908 166,445 150,481
12 OPUC Advice #15-11 0
13 (a)
Oregon Green Tags (254415)327,695 1823 327,695 0 0
14 OPUC Order #11-086 0
15 Idaho Tax Settlement (254451)16,892,588 7,629,912 24,522,500
16 IPUC Order #34071 0
17 Oregon Tax Settlement (254452)578,057 578,057
18 OPUC Order #18-199 0
19 Bridger Depreciation (254800)3,731,897 597,686 4,329,583
20 OPUC Order #12-296 0
21 RL-WAQC CRYOVR (254901)771,882 401 282,554 404,157 893,485
22 Revenue Sharing (254101)0 568,771 568,771
23 IPUC Order #29505 0
24 IPUC Order #33149 0
25 Unfunded Accum Def Income Tax (254966)33,839,389 4,101,518 37,940,907
26 RL-DEF INC TAX-ARAM (254967)178,996,576 282 9,852,578 894,679 170,038,677
27 RL-DEF INC TAX-ARAM GROSS-UP (254968)62,043,790 190 3,415,100 310,113 58,938,803
28 (b)
Idaho PCA Deferral 14,681,373 1823 14,681,373 0
29 IPUC Order Pending 0
30 (c)
Boardman Decommissioning 1,309,454 1,457,496 2,766,950
31 OPUC Order #12-235, IPUC Order #32457 0
32 Market-to-Market Short Term (254203)0 890,345 890,345
33 Minor items (1)11,039 1,635 12,674
41 TOTAL 319,779,040 53,475,744 44,785,538 311,088,834
FERC FORM NO. 1 (REV 02-04)
Page 278
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Account was reclassed to a regulatory asset to net against other power cost adjustment regulatory accounts, to be reported as a net Regulatory Asset on the year-end financial statements.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
The PCA deferral is composed of multiple accounts aggregated into one line for clean presentation in the year-end financial statements; the 12/31/21 balance was in a net Regulatory Asset position and reported on page 232.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
The Boardman Decommissioning is composed of multiple accounts aggregated into one line for clean presentation in the year-end financial statements.
FERC FORM NO. 1 (REV 02-04)
Page 278
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
Electric Operating Revenues
Line
No.
Title of Account
(a)
Operating Revenues Year to Date
Quarterly/Annual
(b)
Operating Revenues Previous
year (no Quarterly)
(c)
MEGAWATT HOURS SOLD Year to
Date Quarterly/Annual
(d)
MEGAWATT HOURS SOLD
Amount Previous year (no
Quarterly)
(e)
AVG.NO. CUSTOMERS PER
MONTH Current Year (no
Quarterly)
(f)
AVG.NO.
CUSTOMERS
PER MONTH
Previous
Year (no
Quarterly)
(g)
1 Sales of Electricity
2 (440) Residential Sales 584,718,584 548,813,944 5,644,996 5,462,557 499,216 484,432
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)481,561,025 445,695,226 6,261,255 5,966,256 92,932 91,470
5 Large (or Ind.) (See Instr. 4)196,176,848 181,631,234 3,471,486 3,369,260 127 127
6 (444) Public Street and Highway Lighting 3,946,139 3,816,533 28,062 30,187 4,118 3,767
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 1,266,402,596 1,179,956,937 15,405,799 14,828,260 596,393 579,796
11 (447) Sales for Resale 90,426,613 66,090,671 1,339,089 1,887,139
12 TOTAL Sales of Electricity 1,356,829,209 1,246,047,608 16,744,888 16,715,399 596,393 579,796
13 (Less) (449.1) Provision for Rate Refunds 9,348,898 7,774,230
14 TOTAL Revenues Before Prov. for Refunds 1,347,480,311 1,238,273,378 16,744,888 16,715,399 596,393 579,796
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues (a)4,655,727 4,352,130
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property 18,384,621 17,491,314
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues (b)30,722,858 43,359,150
22 (456.1) Revenues from Transmission of Electricity of
Others 54,924,770 43,907,734
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25 Other Miscellaneous Operating Revenues
26 TOTAL Other Operating Revenues 108,687,976 109,110,328
27 TOTAL Electric Operating Revenues 1,456,168,287 1,347,383,706
Line12, column (b) includes $ 1,041,859 of unbilled revenues.
Line12, column (d) includes (15,068) MWH relating to unbilled revenues
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: MiscellaneousServiceRevenues
This amount consists of:
Service Establishment/Connection Charges $ 4,231,000
(Includes late and after hour charges)
Misc. Under $250,000 424,727
Total Account 451 $ 4,655,727
(b) Concept: OtherElectricRevenue
This amount consists of:
DSM Activity $ 29,920,448
Alternate distribution Service 802,320
Misc. Under $250,000 90
Total Account 456 $ 30,722,858
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 01 - RESIDENTIAL 5,594,034 579,720,097 490,496 11,404.8514 0.1036
2 03 - Residential Master Meter 4,949 489,180 20 244,406.0741 0.0988
3 04 - Residential EW 0 0 0
4 05 - Residential TOD 17,584 1,760,637 1,014 17,349.6221 0.1001
5 06 - Residentail On-Site Generation 39,730 4,385,230 7,686 5,169.3373 0.1104
6 15 - DUSK TO DAWN LIGHT 2,100 636,927 0 0.3032
7 OTHER 0 (2,137,973)0
41 TOTAL Billed Residential Sales 5,658,397 584,854,098 499,216 11,334.5666 0.1034
42 TOTAL Unbilled Rev. (See Instr. 6)(13,401)(135,514)0.0101
43 TOTAL 5,644,996 584,718,584 499,216 11,307.7225 0.1036
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 7 - GENERAL SERVICE 154,188 19,551,584 32,136 4,797.9836 0.1268
2 8 - GENERAL SERVICE 135 19,141 58 2,327.5862 0.1418
3 9P - GENERAL SERVICE 591,360 38,922,671 280 2,112,000 0.0658
4 9S - GENERAL SERVICE 3,368,272 251,477,040 37,537 89,732.051 0.0747
5 9T - GENERAL SERVICE 6,756 464,500 5 1,351,200 0.0688
6 15 - DUSK TO DAWN 3,574 737,961 0.2065
7 24S - IRRIGATION & PUMP 2,125,733 170,324,111 21,766 97,663.0065 0.0801
8 24T - IRRIGATION & PUMP
9 40 - GENERAL SERVICE 13,143 1,143,753 1,150 11,428.6957 0.087
10 OTHER (1,618,048)
41 TOTAL Billed Small or Commercial 6,263,161 481,022,713 92,932 67,395.0953 0.0768
42 TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)(1,906)538,312 (0.2824)
43 TOTAL Small or Commercial 6,261,255 481,561,025 92,932 67,374.5857 0.0769
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 19P - UNIFORM RATE 2,419,354 141,022,434 121 19,994,661.157 0.0583
2 19S - UNIFORM RATE
3 19T - UNIFORM RATE 140,033 8,601,347 3 46,677,666.6667 0.0614
4 15 - DUSK TO DAWN 18 3,458 0.1921
5 SPECIAL CONTRACTS 911,735 46,941,347 3 303,911,666.6667 0.0515
6 OTHER (1,019,490)
41 TOTAL Billed Large (or Ind.) Sales 3,471,140 195,549,096 127 27,331,811.0236 0.0563
42 TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)346 627,752 1.8143
43 TOTAL Large (or Ind.)3,471,486 196,176,848 127 27,334,535.4331 0.0565
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Commercial and Industrial Sales
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL 0 0
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 40 - GENERAL SERVICE 788 68,837 484 1,628.8645 0.0874
2 41 - MUNICIPAL LIGHTING (A,B,C)24,511 3,683,787 2,878 8,516.6782 0.1503
3 42 - SIGNAL LIGHTING 2,870 182,937 756 3,795.2933 0.0638
4 OTHER 0 (731)0
41 TOTAL Billed Public Street and Highway Lighting 28,169 3,934,830 4,118 6,840.4565 0.1397
42 TOTAL Unbilled Rev. (See Instr. 6)(107)11,309 (0.1057)
43 TOTAL 28,062 3,946,139 4,118 6,814.473 0.1406
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Other Sales to Public Authorities 0
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL 0
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Sales To Railroads and Railways 0
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL 0
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Interdepartmental Sales 0
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL 0
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Provision For Rate Refunds 0
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL 9,348,898 0
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
41 TOTAL Billed - All Accounts 15,420,867 1,265,360,737 596,393 25,856.888 0.0821
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts (15,068)1,041,859 (0.0691)
43 TOTAL - All Accounts 15,405,799 1,266,402,596 596,393 25,831.6228 0.0822
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SALES FOR RESALE (Account 447)
ACTUAL DEMAND (MW)ACTUAL DEMAND (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
FERC Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand (MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
1 3PR Trading Inc SF WSPP
2 ADM Investor Services, Inc.(a)
OS WSPP
3 Arizona Public Service Co.SF WSPP
4 Avangrid Renewables, LLC (b)
OS OATT
5 AVANGRID RENEWABLES, LLC SF WSPP
6 Avista Corp.SF WSPP
7 Avista Corp. - WWP Div.(c)
OS OATT
8 Black Hills Power Inc.(d)
OS OATT
9 Black Hills Power Inc.SF WSPP
10 Bonneville Power (e)
OS OATT
11 Bonneville Power Administration SF WSPP
12 BP Energy Company SF WSPP
13 British Columbia Hydro and Power Authority (f)
OS WSPP
14 Brookfield Renewable Trading & Marketing (g)
OS OATT
15 Brookfield Renewable Trading and Marketing LP SF WSPP
16 California Independent System Operator (h)
SF CAISO
17 Calpine Energy Solutions LLC SF WSPP
18 Chelan Co PUD SF WSPP
19 Citigroup Energy Inc.(i)
OS ISDA
20 Citigroup Energy Inc.SF ISDA
21 Clatskanie PUD SF WSPP
22 Clean Power Alliance of Southern California SF WSPP
23 ConocoPhillips Company (j)
OS OATT
24 ConocoPhillips Company SF WSPP
25 Constellation Energy Generation, LLC SF WSPP
26 Direct Energy Business Marketing, LLC SF WSPP
27 DTE Energy Trading, Inc.SF WSPP
28 Dynasty Power Inc.(k)
OS OATT
29 EDF Trading North America (l)
OS OATT
30 EDF Trading North America, LLC SF WSPP
31 Energy Keepers, Inc.(m)
OS OATT
32 Eugene Water & Electric Board SF WSPP
33 Guzman Energy Group LLC (n)
OS OATT
34 Guzman Energy LLC SF WSPP
35 Macquarie Energy LLC (o)
OS OATT
36 Macquarie Energy LLC SF WSPP
37 MAG Energy Solutions (p)
OS OATT
38 Mercuria Energy America, LLC (q)
OS OATT
39 Morgan Stanley Capital Group Inc.(r)
OS OATT
40 Morgan Stanley Capital Group Inc.SF ISDA
41 Nevada Power (s)
OS OATT
42 Nevada Power Company, dba NV Energy SF WSPP
43 NextEra Energy Marketing, LLC SF WSPP
44 NorthWestern Energy SF WSPP
45 PacifiCorp (t)
OS T-7
46 PacifiCorp SF WSPP
47 PacifiCorp Inc.(u)
OS OATT
48 Portland General Electric Company (v)
OS OATT
49 Portland General Electric Company SF WSPP
50 Powerex Corp.(w)
OS OATT
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
51 Powerex Corp.SF WSPP
52 Public Service Company of Colorado SF WSPP
53 Puget Sound Energy, Inc.SF WSPP
54 Rainbow Energy Marketing Corporation (x)
OS OATT
55 Rainbow Energy Marketing Corporation SF WSPP
56 Seattle City Light SF WSPP
57 Shell Energy North America (US), L.P.(y)
OS OATT
58 Shell Energy North America (US), L.P.SF WSPP
59 Sierra Pacific Power Co., dba NV Energy (z)
OS T-7
60 Sierra Pacific Power Co., dba NV Energy (aa)
OS WSPP
61 Snohomish County PUD SF WSPP
62 Tacoma Power SF WSPP
63 TEC Energy Inc.(ab)
OS OATT
64 Tenaska Power Services Co.(ac)
OS OATT
65 Tenaska Power Services Co.SF WSPP
66 The Energy Authority, Inc.(ad)
OS OATT
67 The Energy Authority, Inc.SF WSPP
68 TransAlta Energy Marketing (U.S.) Inc.(ae)
OS OATT
69 TransAlta Energy Marketing (U.S.) Inc.SF WSPP
70 Transmission Penalty Distribution (af)
OS -
71 Utah Associated Municipal Power Systems (ag)
OS OATT
72 Utah Associated Municipal Power Systems SF WSPP
73 Vitol Inc.(ah)
OS OATT
74 Vitol Inc.SF WSPP
75 Western Area Power Administration (WACM)(ai)
OS T-7
76 Western Area Power Administration (WACM)(aj)
OS WSPP
15 Subtotal - RQ
16 Subtotal-Non-RQ
17 Total
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
SALES FOR RESALE (Account 447)
ACTUAL DEMAND (MW)ACTUAL DEMAND (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
FERC Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand (MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
SALES FOR RESALE (Account 447)
REVENUE REVENUE REVENUE
Line
No.
Megawatt Hours Sold
(g)
Demand Charges ($)
(h)
Energy Charges ($)
(i)
Other Charges ($)
(j)
Total ($) (h+i+j)
(k)
1 331,400 0 16,578,994 0 16,578,994
2 0 0 0 1,033,220 1,033,220
3 25 0 795 0 795
4 0 0 0 10,351 10,351
5 84,731 0 6,746,958 0 6,746,958
6 15,564 0 655,181 0 655,181
7 0 0 0 7,869 7,869
8 0 0 0 2,379 2,379
9 630 0 24,700 0 24,700
10 0 0 0 3,899,592 3,899,592
11 114,583 0 6,213,248 0 6,213,248
12 24,877 0 1,819,541 0 1,819,541
13 13 0 0 1,305 1,305
14 0 0 0 2,260 2,260
15 1,244 0 68,629 0 68,629
16 78,814 0 8,827,882 0 8,827,882
17 59,400 0 4,608,948 0 4,608,948
18 1,397 0 33,026 0 33,026
19 0 0 0 12,696 12,696
20 35,937 0 2,592,327 0 2,592,327
21 509 0 26,535 0 26,535
22 94,600 0 4,830,096 0 4,830,096
23 0 0 0 1,625 1,625
24 249 0 9,156 0 9,156
25 1,086 0 55,116 0 55,116
26 123,840 0 5,474,914 0 5,474,914
27 170,510 0 7,095,486 0 7,095,486
28 0 0 0 116,164 116,164
29 0 0 0 7,204 7,204
30 11,762 0 701,619 0 701,619
31 0 0 0 7,529 7,529
32 2,893 0 143,092 0 143,092
33 0 0 0 58,911 58,911
34 745 0 35,685 0 35,685
35 0 0 0 154,760 154,760
36 10,150 0 643,106 0 643,106
37 0 0 0 2,185 2,185
38 0 0 0 179,779 179,779
39 0 0 0 1,518,965 1,518,965
40 6,941 0 827,840 0 827,840
41 0 0 0 3,694 3,694
42 1,995 0 315,415 0 315,415
43 295 0 16,570 0 16,570
44 3,617 0 170,980 0 170,980
45 168 0 0 8,134 8,134
46 1,695 0 23,130 0 23,130
47 0 0 0 5,256,244 5,256,244
48 0 0 0 77,464 77,464
49 14,518 0 590,433 0 590,433
50 0 0 0 1,094,838 1,094,838
51 2,406 0 131,306 0 131,306
52 215 0 6,654 0 6,654
53 4,580 0 225,731 0 225,731
54 0 0 0 76,918 76,918
55 8,342 0 383,291 0 383,291
56 10,157 0 368,548 0 368,548
57 0 0 0 223,140 223,140
58 69,474 0 3,637,304 0 3,637,304
59 16 0 0 1,535 1,535
60 5 0 0 221 221
61 1,550 0 72,910 0 72,910
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
62 410 0 9,840 0 9,840
63 0 0 0 503 503
64 0 0 0 120,502 120,502
65 3,600 113,363 0 113,363
66 0 0 0 85,157 85,157
67 19,614 981,352 0 981,352
68 0 0 0 142,089 142,089
69 3,156 219,615 0 219,615
70 0 0 0 18,735 18,735
71 0 0 0 10,183 10,183
72 12,800 508,174 0 508,174
73 0 0 0 11,976 11,976
74 8,271 0 471,066 0 471,066
75 178 0 0 12,754 12,754
76 127 0 0 7,176 7,176
15 0
16 1,339,089 0 76,258,556 14,168,057 90,426,613
17 1,339,089 0 76,258,556 14,168,057 90,426,613
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
SALES FOR RESALE (Account 447)
REVENUE REVENUE REVENUE
Line
No.
Megawatt Hours Sold
(g)
Demand Charges ($)
(h)
Energy Charges ($)
(i)
Other Charges ($)
(j)
Total ($) (h+i+j)
(k)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: StatisticalClassificationCode
ADM Investor Services, Inc Futures Account Document, dated May 6, 2015
(b) Concept: StatisticalClassificationCode
Financial Transmission Losses
(c) Concept: StatisticalClassificationCode
Financial Transmission Losses
(d) Concept: StatisticalClassificationCode
Financial Transmission Losses
(e) Concept: StatisticalClassificationCode
Financial Transmission Losses
(f) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(g) Concept: StatisticalClassificationCode
Financial Transmission Losses
(h) Concept: StatisticalClassificationCode
Includes actual billing and estimate accrual
(i) Concept: StatisticalClassificationCode
ISDA Master Agreement With Citigroup, dated March 7, 2011
(j) Concept: StatisticalClassificationCode
Financial Transmission Losses
(k) Concept: StatisticalClassificationCode
Financial Transmission Losses
(l) Concept: StatisticalClassificationCode
Financial Transmission Losses
(m) Concept: StatisticalClassificationCode
Financial Transmission Losses
(n) Concept: StatisticalClassificationCode
Financial Transmission Losses
(o) Concept: StatisticalClassificationCode
Financial Transmission Losses
(p) Concept: StatisticalClassificationCode
Financial Transmission Losses
(q) Concept: StatisticalClassificationCode
Financial Transmission Losses
(r) Concept: StatisticalClassificationCode
Financial Transmission Losses
(s) Concept: StatisticalClassificationCode
Financial Transmission Losses
(t) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(u) Concept: StatisticalClassificationCode
Financial Transmission Losses
(v) Concept: StatisticalClassificationCode
Financial Transmission Losses
(w) Concept: StatisticalClassificationCode
Financial Transmission Losses
(x) Concept: StatisticalClassificationCode
Financial Transmission Losses
(y) Concept: StatisticalClassificationCode
Financial Transmission Losses
(z) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(aa) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ab) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ac) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ad) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ae) Concept: StatisticalClassificationCode
Financial Transmission Losses
(af) Concept: StatisticalClassificationCode
Transmission penalty distribution credits
(ag) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ah) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ai) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(aj) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering 900,983 1,423,007
5 (501) Fuel 95,323,833 119,677,855
6 (502) Steam Expenses 9,231,056 9,790,106
7 (503) Steam from Other Sources 0
8 (Less) (504) Steam Transferred-Cr.0
9 (505) Electric Expenses 1,282,126 1,754,144
10 (506) Miscellaneous Steam Power Expenses 8,485,407 9,778,684
11 (507) Rents 216,915 220,267
12 (509) Allowances 0
13 TOTAL Operation (Enter Total of Lines 4 thru 12)115,440,320 142,644,063
14 Maintenance
15 (510) Maintenance Supervision and Engineering (1,754)9,350
16 (511) Maintenance of Structures 1,278,996 383,245
17 (512) Maintenance of Boiler Plant 8,910,438 8,491,253
18 (513) Maintenance of Electric Plant 2,692,331 3,148,003
19 (514) Maintenance of Miscellaneous Steam Plant 8,056,749 3,597,407
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)20,936,760 15,629,258
21 TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)136,377,080 158,273,321
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering 0
25 (518) Fuel 0
26 (519) Coolants and Water 0
27 (520) Steam Expenses 0
28 (521) Steam from Other Sources 0
29 (Less) (522) Steam Transferred-Cr.0
30 (523) Electric Expenses 0
31 (524) Miscellaneous Nuclear Power Expenses 0
32 (525) Rents 0
33 TOTAL Operation (Enter Total of lines 24 thru 32)0
34 Maintenance
35 (528) Maintenance Supervision and Engineering 0
36 (529) Maintenance of Structures 0
37 (530) Maintenance of Reactor Plant Equipment 0
38 (531) Maintenance of Electric Plant 0
39 (532) Maintenance of Miscellaneous Nuclear Plant 0
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)0
41 TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)0
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 5,427,508 5,840,433
45 (536) Water for Power 5,677,053 6,916,183
46 (537) Hydraulic Expenses 16,085,623 14,955,630
47 (538) Electric Expenses 1,781,395 2,104,297
48 (539) Miscellaneous Hydraulic Power Generation Expenses 4,915,529 4,930,647
49 (540) Rents 306,561 257,897
50 TOTAL Operation (Enter Total of Lines 44 thru 49)34,193,669 35,005,087
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 134,378 211,923
54 (542) Maintenance of Structures 993,194 701,385
55 (543) Maintenance of Reservoirs, Dams, and Waterways 596,164 427,177
56 (544) Maintenance of Electric Plant 2,630,296 2,507,845
57 (545) Maintenance of Miscellaneous Hydraulic Plant 3,066,271 3,016,807
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)7,420,303 6,865,137
59 TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)41,613,972 41,870,224
60 D. Other Power Generation
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
61 Operation
62 (546) Operation Supervision and Engineering 590,913 673,850
63 (547) Fuel 85,225,955 53,062,458
64 (548) Generation Expenses 4,772,834 4,617,761
64.1 (548.1) Operation of Energy Storage Equipment
65 (549) Miscellaneous Other Power Generation Expenses 1,475,129 839,793
66 (550) Rents 0
67 TOTAL Operation (Enter Total of Lines 62 thru 67)92,064,831 59,193,862
68 Maintenance
69 (551) Maintenance Supervision and Engineering 0
70 (552) Maintenance of Structures 163,959 174,834
71 (553) Maintenance of Generating and Electric Plant 72,744 135,593
71.1 (553.1) Maintenance of Energy Storage Equipment
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 2,184,732 1,865,786
73 TOTAL Maintenance (Enter Total of Lines 69 thru 72)2,421,435 2,176,213
74 TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)94,486,266 61,370,075
75 E. Other Power Supply Expenses
76 (555) Purchased Power 386,658,508 292,909,857
76.1 (555.1) Power Purchased for Storage Operations
77 (556) System Control and Load Dispatching 355 6,313
78 (557) Other Expenses (44,579,887)(28,389,336)
79 TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)342,078,976 264,526,834
80 TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)614,556,294 526,040,454
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering 2,899,726 2,861,348
85 (561.1) Load Dispatch-Reliability 38,058 19,380
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 2,930,439 2,732,930
87 (561.3) Load Dispatch-Transmission Service and Scheduling 871,560 995,649
88 (561.4) Scheduling, System Control and Dispatch Services 12,934 9,834
89 (561.5) Reliability, Planning and Standards Development 0
90 (561.6) Transmission Service Studies 76,035 3,416
91 (561.7) Generation Interconnection Studies 103,680 41,502
92 (561.8) Reliability, Planning and Standards Development Services 1,266,365 1,054,598
93 (562) Station Expenses 3,030,864 2,782,705
93.1 (562.1) Operation of Energy Storage Equipment
94 (563) Overhead Lines Expenses 1,055,067 884,293
95 (564) Underground Lines Expenses 0
96 (565) Transmission of Electricity by Others 7,022,556 4,027,586
97 (566) Miscellaneous Transmission Expenses 0 1,000,000
98 (567) Rents 4,568,113 4,011,443
99 TOTAL Operation (Enter Total of Lines 83 thru 98)23,875,397 20,424,684
100 Maintenance
101 (568) Maintenance Supervision and Engineering 184,291 153,823
102 (569) Maintenance of Structures 0
103 (569.1) Maintenance of Computer Hardware 39,953 35,657
104 (569.2) Maintenance of Computer Software 1,461,285 1,300,103
105 (569.3) Maintenance of Communication Equipment 27,006 24,014
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant 0
107 (570) Maintenance of Station Equipment 1,774,304 1,862,959
107.1 (570.1) Maintenance of Energy Storage Equipment
108 (571) Maintenance of Overhead Lines 1,126,974 1,437,562
109 (572) Maintenance of Underground Lines 0
110 (573) Maintenance of Miscellaneous Transmission Plant 2,545 486
111 TOTAL Maintenance (Total of Lines 101 thru 110)4,616,358 4,814,604
112 TOTAL Transmission Expenses (Total of Lines 99 and 111)28,491,755 25,239,288
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capacity Market Facilitation
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services 732,683 515,586
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)732,683 515,586
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)0
131 TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)732,683 515,586
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 4,083,135 4,070,045
135 (581) Load Dispatching 4,899,999 4,963,439
136 (582) Station Expenses 1,579,041 1,671,271
137 (583) Overhead Line Expenses 4,854,331 4,236,429
138 (584) Underground Line Expenses 4,573,059 4,293,014
138.1 (584.1) Operation of Energy Storage Equipment
139 (585) Street Lighting and Signal System Expenses 561 8,448
140 (586) Meter Expenses 5,014,025 4,608,642
141 (587) Customer Installations Expenses 1,011,897 1,022,228
142 (588) Miscellaneous Expenses 4,109,601 4,135,289
143 (589) Rents 439,479 329,158
144 TOTAL Operation (Enter Total of Lines 134 thru 143)30,565,128 29,337,963
145 Maintenance
146 (590) Maintenance Supervision and Engineering 10,926 14,730
147 (591) Maintenance of Structures 0
148 (592) Maintenance of Station Equipment 4,077,874 3,827,943
148.1 (592.2) Maintenance of Energy Storage Equipment
149 (593) Maintenance of Overhead Lines 17,694,888 15,988,062
150 (594) Maintenance of Underground Lines 597,945 533,170
151 (595) Maintenance of Line Transformers 57,820 48,699
152 (596) Maintenance of Street Lighting and Signal Systems 263,541 270,062
153 (597) Maintenance of Meters 841,948 839,202
154 (598) Maintenance of Miscellaneous Distribution Plant 98,043 139,835
155 TOTAL Maintenance (Total of Lines 146 thru 154)23,642,985 21,661,703
156 TOTAL Distribution Expenses (Total of Lines 144 and 155)54,208,113 50,999,666
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 841,926 719,969
160 (902) Meter Reading Expenses 1,871,924 1,962,900
161 (903) Customer Records and Collection Expenses 14,000,067 14,723,735
162 (904) Uncollectible Accounts 2,363,140 5,224,630
163 (905) Miscellaneous Customer Accounts Expenses 423 130
164 TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)19,077,480 22,631,364
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision 793,300 727,173
168 (908) Customer Assistance Expenses 36,468,097 49,413,907
169 (909) Informational and Instructional Expenses 294,369 296,792
170 (910) Miscellaneous Customer Service and Informational Expenses 850,624 737,634
171 TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)38,406,390 51,175,506
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision 0
175 (912) Demonstrating and Selling Expenses 0
176 (913) Advertising Expenses 0
177 (916) Miscellaneous Sales Expenses 0
178 TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)0
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 87,358,103 86,989,181
182 (921) Office Supplies and Expenses 14,005,146 13,634,146
183 (Less) (922) Administrative Expenses Transferred-Credit 32,764,226 29,768,610
184 (923) Outside Services Employed 7,828,424 6,803,893
185 (924) Property Insurance 3,571,061 4,105,815
186 (925) Injuries and Damages 6,484,661 6,029,651
187 (926) Employee Pensions and Benefits 56,595,140 48,877,499
188 (927) Franchise Requirements 0
189 (928) Regulatory Commission Expenses 6,675,237 5,930,278
190 (929) (Less) Duplicate Charges-Cr.0
191 (930.1) General Advertising Expenses 381,688 168,222
192 (930.2) Miscellaneous General Expenses 4,090,496 3,692,278
193 (931) Rents 0
194 TOTAL Operation (Enter Total of Lines 181 thru 193)154,225,730 146,462,353
195 Maintenance
196 (935) Maintenance of General Plant 7,816,747 7,451,927
197 TOTAL Administrative & General Expenses (Total of Lines 194 and 196)162,042,477 153,914,280
198 TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and
197)917,515,192 830,516,144
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
1 American Falls Solar, LLC LU 45,664
2 American Falls Solar II, LLC LU 46,819
3 Allan Ravenscroft/Malad River LU -1,312
4 Baker City Hydro LU 928
5 Bannock County Landfill LU 12,323
6 Bennett Creek Wind Farm LU 42,942
7 Benson Creek Windfarm LU 33,259
8 Black Canyon Bliss Hydro LU -141
9 Blind Canyon LU -4,482
10 Branchflower - Trout Company LU -630
11 Burley Butte Wind Park LU 64,325
12 CAFCO Idaho Refuse Management LLC - SISW LFGE LU -18,176
13 Camp Reed Wind Park LU 71,031
14 Cassia Wind Farm LLC LU 18,982
15 CCP OR Tenant 1, LLC
16 Grove Solar Center, LLC LU 13,175
17 Hyline Solar Center, LLC LU 14,670
18 Open Range Solar Center, LLC LU 22,787
19 Railroad Solar Center, LLC LU 10,340
20 Thunderegg Solar Center, LLC LU 22,508
21 Vale Air Solar Center, LLC LU 22,493
22 Central Rivers Power US LLC
23 Barber Dam LU 4,064
24 Dietrich Drop LU 14,224
25 Lowline #2 (a)
LU 3,065
26 City of Hailey LU -102
27 City of Pocatello LU -1,672
28 Clear Springs Trout LU -3,338
29 Clifton E. Jenson - Birch Creek LU -357
30 Cold Springs Windfarm LU -52,699
31 College of Southern Idaho - Pristine Springs #1 LU -813
32 College of Southern Idaho - Pristine Springs #3 LU -1,686
33 Crystal Springs LU -9,442
34 Curry Cattle Company (b)
LU -679
35 Cycle Horseshoe Bend Wind LU -22,272
36 David R Snedigar LU -1,228
37 Desert Meadow Windfarm LU -60,657
38 Durbin Creek Windfarm LU 29,246
39 Eightmile Hydro Project LU -936
40 Enerparc Solar Development LLC
41 Baker Solar Center LU 33,699
42 Brush Solar LU 6,431
43 Morgan Solar LU 7,016
44 Ontario Solar Center LU 7,135
45 Vale I Solar LU 5,919
46 Faulkner Ranch LU -3,324
47 Fisheries Development LU -472
48 Fossil Gulch Wind LU -26,570
49 Hidden Hollow Energy LU -25,310
50 Golden Valley Wind Park LU -35,057
51 Grand View PV Solar Two LU -189,546
52 Hammett Hill Windfarm LU -59,701
53 Hazelton B (c)
LU -23,868
54 High Mesa Wind Project LU -93,651
55 H.K. Hydro Mud Creek S & S LU -1,353
56 Horseshoe Bend Hydro LU -37,742
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
57 Hot Springs Wind Farm LU 34,844
58 Hydroland
59 Elk Creek LU 2,483
60 Rock Creek #2 (d)
LU -4,838
61 ID Solar 1 LU 94,745
62 Idaho Winds - Sawtooth Wind Project LU -59,602
63 J R Simplot Co.LU -61,912
64 J.M. Miller/Sahko Hydro LU 1,283
65 Jett Creek Windfarm LU 28,985
66 John R LeMoyne LU -612
67 Kootenai Electric Cooperative - Fighting Creek LU -9,852
68 Koosh Inc. Geo Bon #2 LU -3,008
69 Koyle Small Hydro LU -2,939
70 Lateral #10 LU -4,970
71 Lemhi Hydro Power Co.- Schaffner LU -769
72 Lime Wind Energy LU 6,320
73 Little Mac Power Co./Cedar Draw LU -4,973
74 Little Wood River Irrigation District LU -1,375
75 Mainline Windfarm LU -58,038
76 Marco Ranches LU -2,571
77 Marysville Hydro Partners- Falls River (e)
LU -37,295
78 McCollum Enterprises -Canyon Springs LU -624
79 MC6 Hydro LU -5,781
80 Milner Dam Wind Park LU 58,962
81 Mountain Home Solar I, LLC LU 47,194
82 Mud Creek White Hydro, Inc LU -361
83 Murphy Flat Power, LLC LU 43,904
84 North Gooding Main Hydro (f)
LU -4,027
85 North Side Energy Company Inc
86 Bypass LU -28,075
87 Hazelton A LU -24,908
88 Head of U Canal Project LU -4,460
89 Orchard Ranch Solar, LLC LU 46,252
90 Oregon Trail Wind Park LU 41,189
91 Owyhee Irrigation District
92 Mitchell Butte LU -3,460
93 Owyhee Dam Cspp LU -10,201
94 Tunnel #1 LU -6,098
95 Payne's Ferry Wind Park LU 67,718
96 Pico Energy, LLC LU 12,152
97 Pigeon Cove Power LU -7,786
98 Pilgrim Stage Station Wind Park LU 35,397
99 Prospector Windfarm LU 30,931
100 Reynolds Irrigation LU -946
101 Richard Kaster
102 Box Canyon LU -1,875
103 Briggs Creek LU -3,559
104 Riverside Hydro - Mora Drop LU 3,984
105 Riverside Investments
106 Arena Drop LU 1,507
107 Fargo Drop Hydroelectric LU 3,045
108 Rockland Wind Farm LU 276,092
109 Ryegrass Windfarm LU 54,992
110 Salmon Falls Wind LU 66,230
111 Shingle Creek LU -944
112 Shorock Hydro Inc.
113 Rock Creek #1 LU 9,897
114 Shoshone CSPP LU -1,302
115 Shoshone #2 LU -2,183
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
116 Simcoe Solar, LLC LU 48,174
117 Snake River Pottery LU -429
118 South Forks Joint Venture-Lowline Canal (g)
LU -26,135
119 Tamarack Energy Partnership LU -19,785
120 Tasco - Nampa (h)
OS -39
121 Tasco - Twin Falls (i)
OS 0
122 Thousand Springs Wind Park LU 34,327
123 Tiber Montana LLC - Tiber Dam LU 29,471
124 Tuana Gulch Wind Park LU 32,392
125 Tuana Springs Expansion (j)
LU 74,496
126 Twin Falls Energy-Lowline Midway Hydro LU 7,954
127 Two Ponds Windfarm LU -62,043
128 White Water Ranch LU -727
129 William Arkoosh-Littlewood River Ranch I LU -2,977
130 William Arkoosh- Littlewood River Ranch II LU 3,352
131 Willow Spring Windfarm LU 33,350
132 Wilson Power Company (k)
LU -26,544
133 Wood Hydro
134 Black Canyon #3 (l)
LU 309
135 Jim Knight LU 976
136 Magic Reservoir LU -0
137 Mile 28 (m)
LU 5,395
138 Sagebrush LU 1,313
139 Yahoo Creek Wind Park LU 68,529
140 Scheduling Deviation 3,699
141 ADM Investor Services, Inc.(n)
OS WSPP 0
142 3PR Trading Inc SF WSPP 18,714
143 Arizona Public Service Co.SF WSPP 58,140
144 AVANGRID RENEWABLES, LLC (o)
OS WSPP 3
145 AVANGRID RENEWABLES, LLC SF WSPP 134,600
146 Avista Corp.(p)
OS WSPP 14
147 Avista Corp.(q)
OS WSPP 0
148 Avista Corp.SF WSPP 4,500
149 Bonneville Power Administration (r)
OS WSPP 85
150 Bonneville Power Administration (s)
OS WSPP 0
151 Bonneville Power Administration SF WSPP 113,808
152 BP Energy Company SF WSPP 744,430
153 Brookfield Renewable Trading and Marketing LP SF WSPP 400
154 California Independent System Operator
(t)
SF CAISO 1,356,147
155 Calpine Energy Solutions LLC SF WSPP 4,226
156 Chelan Co PUD (u)
OS WSPP 1
157 Chelan Co PUD SF WSPP 80,800
158 Citigroup Energy Inc.(v)
OS WSPP 0
159 Citigroup Energy Inc.SF WSPP 20,800
160 Clatskanie PUD SF WSPP 400
161 Clean Power Alliance of Southern California SF WSPP 1,473
162 ConocoPhillips Company SF WSPP 30,800
163 Constellation Energy Generation, LLC SF WSPP 2,000
164 Direct Energy Business Marketing, LLC SF WSPP 648
165 DTE Energy Trading, Inc.SF WSPP 1,097
166 Dynasty Power Inc.SF WSPP 2,200
167 EDF Trading North America, LLC SF WSPP 43,744
168 Eugene Water & Electric Board SF WSPP 800
169 Grant CO Public Utility District #2 -- Electric System (w)
OS WSPP 4
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
170 Gridforce Energy Management, LLC (x)
OS WSPP 2
171 Macquarie Energy LLC SF ISDA 58,552
172 Morgan Stanley Capital Group Inc.SF WSPP 57,600
173 Neal Hot Springs Unit #1 LU -92,943
174 Nevada Power Company, dba NV Energy (y)
OS WSPP 0
175 Nevada Power Company, dba NV Energy SF WSPP 2,430
176 NextEra Energy Marketing, LLC SF WSPP 64,060
177 NorthWestern Energy (z)
OS WSPP 4
178 NorthWestern Energy (Transmission)(aa)
OS WSPP 0
179 NorthWestern Energy (Transmission)(ab)
OS WSPP 8
180 Oregon Solar Customers (ac)
OS -737
181 PacifiCorp
(ad)
OS WSPP 79
182 PacifiCorp SF WSPP 25,600
183 PacifiCorp Inc.(ae)
OS WSPP 0
184 Portland General Electric Company (af)
OS WSPP 22
185 Portland General Electric Company SF WSPP 19,613
186 Powerex Corp.SF WSPP 51,006
187 Public Service Company of Colorado SF WSPP 20,400
188 Puget Sound Energy, Inc.(ag)
OS WSPP 27
189 Puget Sound Energy, Inc.SF WSPP 43,407
190 Raft River Energy I LLC LU -345,034
191 Rainbow Energy Marketing Corporation SF WSPP 825
192 Seattle City Light (ah)
OS WSPP 7
193 Seattle City Light SF WSPP 10,207
194 Shell Energy North America (US), L.P.SF WSPP 110,554
195 Sierra Pacific Power Co., dba NV Energy (ai)
OS WSPP 48
196 Snohomish County PUD SF WSPP 1,500
197 Tacoma Power SF WSPP 2,800
198 Telocaset Wind Power Partners LLC LU APP-A 182,841
199 Tenaska Power Services Co.SF WSPP 21,760
200 The Energy Authority, Inc.SF WSPP 24,600
201 TransAlta Energy Marketing (U.S.) Inc.SF WSPP 9,000
202 Tri-State Generation and Transmission Association SF WSPP 800
203 Vitol Inc.SF WSPP 22,800
204 Western Area Power Administration (WACM)(aj)
OS WSPP 28
205 PacifiCorp Inc.(ak)
EX -
206 Sierra Pacific Power Co., dba NV Energy (al)
EX -
207 Clatskanie PUD (am)
EX 153
208 Acctg Valuation of Clatskanie PUD (an)
EX 0
209 Demand Response Avoided Energy (ao)
OS -0
15 TOTAL 6,829,255
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
1 1,940,944 1,940,944
2 1,928,394 1,928,394
3 71,280 71,280
4 59,453 59,453
5 867,594 867,594
6 2,999,785 2,999,785
7 2,148,612 2,148,612
8 8,648 8,648
9 280,257 280,257
10 41,028 41,028
11 4,032,551 4,032,551
12 662,769 662,769
13 5,783,440 5,783,440
14 1,136,409 1,136,409
15 0
16 902,846 902,846
17 948,283 948,283
18 1,560,097 1,560,097
19 710,419 710,419
20 1,544,622 1,544,622
21 1,542,277 1,542,277
22 0
23 204,919 204,919
24 766,195 766,195
25 152,941 (41,804)111,137
26 3,715 3,715
27 67,978 67,978
28 215,913 215,913
29 20,411 20,411
30 4,337,875 4,337,875
31 46,422 46,422
32 94,998 94,998
33 489,229 489,229
34 55,773 (14,438)41,335
35 1,473,035 1,473,035
36 62,401 62,401
37 4,982,869 4,982,869
38 1,885,691 1,885,691
39 48,890 48,890
40 0
41 1,228,680 1,228,680
42 178,866 178,866
43 194,855 194,855
44 185,139 185,139
45 164,773 164,773
46 259,898 259,898
47 16,923 16,923
48 1,732,888 1,732,888
49 1,837,942 1,837,942
50 2,267,197 2,267,197
51 10,930,535 10,930,535
52 4,935,172 4,935,172
53 1,760,470 1,760,470
54 5,208,156 (22,988)5,185,168
55 78,244 78,244
56 2,744,473 2,744,473
57 2,478,166 2,478,166
58 0
59 88,795 88,795
60 259,502 156,258 415,760
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
61 5,116,782 5,116,782
62 5,458,270 5,458,270
63 3,473,557 3,473,557
64 55,927 55,927
65 1,848,386 1,848,386
66 32,915 32,915
67 873,096 873,096
68 228,284 228,284
69 165,690 165,690
70 223,756 223,756
71 50,498 50,498
72 529,764 529,764
73 278,848 278,848
74 65,937 65,937
75 4,783,922 4,783,922
76 125,785 125,785
77 2,465,369 2,465,369
78 40,544 40,544
79 207,038 207,038
80 3,704,215 3,704,215
81 2,157,373 2,157,373
82 15,517 15,517
83 1,671,797 1,671,797
84 336,283 (71,036)265,247
85 0
86 1,505,192 1,505,192
87 2,177,391 2,177,391
88 434,957 434,957
89 1,711,826 1,711,826
90 2,660,847 2,660,847
91 0
92 101,968 101,968
93 246,755 246,755
94 201,169 201,169
95 5,525,303 5,525,303
96 454,652 454,652
97 432,211 432,211
98 2,295,796 2,295,796
99 1,987,013 1,987,013
100 52,780 52,780
101 0
102 120,319 120,319
103 201,025 201,025
104 285,453 285,453
105 0
106 147,767 147,767
107 218,291 218,291
108 20,335,885 20,335,885
109 4,535,276 4,535,276
110 4,199,049 4,199,049
111 56,797 56,797
112 0
113 631,962 631,962
114 83,617 83,617
115 157,656 157,656
116 1,946,138 1,946,138
117 22,917 22,917
118 1,978,242 1,978,242
119 1,109,322 1,109,322
120 1,386 1,386
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
121 0 0
122 2,234,973 2,234,973
123 1,847,754 1,847,754
124 2,095,704 2,095,704
125 6,869,680 (2,524)6,867,156
126 483,064 483,064
127 5,082,661 5,082,661
128 38,756 38,756
129 208,633 208,633
130 255,132 255,132
131 2,152,651 2,152,651
132 1,963,259 1,963,259
133 0
134 23,223 (7,813)15,410
135 66,575 66,575
136 0 0
137 388,997 102,312 491,309
138 90,349 90,349
139 5,566,416 5,566,416
140 0
141 0 0 0 (991,880)(991,880)
142 0 0 0 1,268,352 0 1,268,352
143 0 0 0 3,219,891 0 3,219,891
144 0 0 0 0 147 147
145 0 0 0 5,009,521 0 5,009,521
146 0 0 0 0 741 741
147 0 0 0 0 538,320 538,320
148 0 0 0 145,192 0 145,192
149 0 0 0 0 4,671 4,671
150 0 0 0 0 735,658 735,658
151 0 0 0 6,431,082 0 6,431,082
152 0 0 0 37,685,383 0 37,685,383
153 0 0 0 15,904 0 15,904
154 0 0 0 26,690,146 0 26,690,146
155 0 0 0 704,182 0 704,182
156 0 0 0 0 20 20
157 0 0 0 3,863,622 0 3,863,622
158 0 0 0 (967,045)(967,045)
159 0 0 0 2,858,064 0 2,858,064
160 0 0 0 59,368 0 59,368
161 0 0 0 191,340 0 191,340
162 0 0 0 1,470,558 0 1,470,558
163 0 0 0 133,000 0 133,000
164 0 0 0 88,913 0 88,913
165 0 0 0 40,616 0 40,616
166 0 0 0 349,120 0 349,120
167 0 0 0 3,288,912 0 3,288,912
168 0 0 0 75,800 0 75,800
169 0 0 0 0 223 223
170 0 0 0 0 96 96
171 0 0 0 4,073,412 0 4,073,412
172 0 0 0 4,507,812 0 4,507,812
173 0 0 0 6,619,281 0 6,619,281
174 0 0 0 0 4,277 4,277
175 0 0 0 131,515 0 131,515
176 0 0 0 2,076,937 0 2,076,937
177 0 0 0 0 191 191
178 0 0 0 0 27,449 27,449
179 0 0 0 0 535 535
180 0 0 0 0 29,691 29,691
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
181 0 0 0 0 4,054 4,054
182 0 0 0 825,220 0 825,220
183 0 0 0 0 289,904 289,904
184 0 0 0 0 1,354 1,354
185 0 0 0 1,807,829 0 1,807,829
186 0 0 0 3,937,013 0 3,937,013
187 0 0 0 983,588 0 983,588
188 0 0 0 0 1,498 1,498
189 0 0 0 1,885,574 0 1,885,574
190 0 0 0 23,495,406 0 23,495,406
191 0 0 0 72,983 0 72,983
192 0 0 0 0 360 360
193 0 0 0 542,523 0 542,523
194 0 0 0 8,551,744 0 8,551,744
195 0 0 0 0 2,386 2,386
196 0 0 0 47,338 0 47,338
197 0 0 0 194,496 0 194,496
198 0 0 0 21,780,588 0 21,780,588
199 0 0 0 1,864,310 0 1,864,310
200 0 0 0 2,134,644 0 2,134,644
201 0 0 0 522,546 0 522,546
202 0 0 0 55,200 0 55,200
203 0 0 0 594,700 0 594,700
204 0 0 0 0 1,473 1,473
205 0 116,053 0
206 0 6,339 0
207 38,171 44,600 0
208 0 0 (276,164)(276,164)
209 0 0 7,132,978 7,132,978
15 0 38,171 166,992 0 380,019,604 6,638,904 386,658,508
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: StatisticalClassificationCode
Net Energy Default Damages
(b) Concept: StatisticalClassificationCode
Delay Damages
(c) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(d) Concept: StatisticalClassificationCode
Net Energy Default Damages
(e) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(f) Concept: StatisticalClassificationCode
Delay Damages
(g) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(h) Concept: StatisticalClassificationCode
Non Firm Purchases
(i) Concept: StatisticalClassificationCode
Non Firm Purchases
(j) Concept: StatisticalClassificationCode
ICE Price Adjustment from February 2020
(k) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(l) Concept: StatisticalClassificationCode
Delay Damages
(m) Concept: StatisticalClassificationCode
Net Energy Default Damages
(n) Concept: StatisticalClassificationCode
ADM Investor Services, Inc Futures Account Document, dated May 5, 2015
(o) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(p) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(q) Concept: StatisticalClassificationCode
Financial Transmission Losses
(r) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(s) Concept: StatisticalClassificationCode
Financial Transmission Losses
(t) Concept: StatisticalClassificationCode
Includes actual billing and estimate accrual
(u) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(v) Concept: StatisticalClassificationCode
ISDA Master Agreement With Citigroup, dated March 7, 2011
(w) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(x) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(y) Concept: StatisticalClassificationCode
Financial Transmission Losses
(z) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(aa) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ab) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ac) Concept: StatisticalClassificationCode
Schedule 88 Oregon Solar
(ad) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ae) Concept: StatisticalClassificationCode
Financial Transmission Losses
(af) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ag) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ah) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ai) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(aj) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ak) Concept: StatisticalClassificationCode
Physical Transmission Losses
(al) Concept: StatisticalClassificationCode
Physical Transmission Losses
(am) Concept: StatisticalClassificationCode
Energy exchange between Clatskanie PUD and Idaho Power Company at Arrowrock Dam
(an) Concept: StatisticalClassificationCode
Energy exchange between Clatskanie PUD and Idaho Power Company at Arrowrock Dam
(ao) Concept: StatisticalClassificationCode
Incentive program for customers to reduce demand during peak hours
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
1 (a)
Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO (i)
9
2 (b)
Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamation FNO 9
3 (c)
Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers FNO 9
4 (d)
Milner Irrigation District United States Bureau of Reclamation Milner Irrigation District OLF (j)
Legacy
Minidoka,
Idaho
Various in
Idaho
5 (e)
Morgan Stanley Capital Group Inc.Seattle City Light Bonneville Power Administration OS (k)
4
6 (f)
PacifiCorp PacifiCorp West PacifiCorp West FNO 9
7 (g)
United States Bureau of Indian Affairs Bonneville Power Administration United States Bureau of Indian Affairs OS Legacy LaGrande,
Oregon
Various in
Idaho
8
(h)
Cycle Horseshoe Bend Wind, LLC PacifiCorp East PacifiCorp East OS
(l)
5/6 BRDY IPCOEAST
9 Cycle Horseshoe Bend Wind, LLC PacifiCorp East PacifiCorp East OS 5/6 JEFF IPCOEAST
10 Tenaska Power Services OS 5/6
11 Vitol Inc.OS 5/6
12 PacifiCorp Inc.PacifiCorp East Bonneville Power Administration LFP (m)
7/8 BORA LAGRANDE
13 PacifiCorp Inc.PacifiCorp East PacifiCorp West LFP 7/8 KPRT HURR
14 PacifiCorp Inc.PacifiCorp East PacifiCorp West LFP 7/8 BORA HURR
15 Morgan Stanley Capital Group Inc.Idaho Power Company Bonneville Power Administration LFP 7/8 LYPK LAGRANDE
16 Bonneville Power Administration PacifiCorp West PacifiCorp East LFP 7/8 M500 KPRT
17 Bonneville Power Administration PacifiCorp West PacifiCorp East LFP 7/8 SMLK KPRT
18 Macquarie Energy, LLC PacifiCorp East PacifiCorp East LFP 7/8 JEFF BORA
19 Powerex Corporation Avista PacifiCorp East LFP 7/8 LOLO BORA
20 Vitol Inc.Idaho Power Company Sierra Pacific Power LFP 7/8 MDSK M345
21 Adapture Renewables, LLC (Baker Solar Center)NF
(n)
11
22 Adapture Renewables, LLC (Morgan Solar)NF 11
23 Adapture Renewables, LLC (Ontario Solar Center)NF 11
24 Adapture Renewables, LLC (Vale I Solar)NF 11
25 American Falls Solar, LLC NF 11
26 American Falls Solar II, LLC NF 11
27 Avangrid Renewables, LLC PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
28 Avangrid Renewables, LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
29 Avangrid Renewables, LLC Bonneville Power Administration Avista NF 7/8 LAGRANDE LOLO
30 Avangrid Renewables, LLC Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
31 Avangrid Renewables, LLC Avista PacifiCorp East NF 7/8 LOLO BORA
32 Avangrid Renewables, LLC Avista Sierra Pacific Power NF 7/8 LOLO M345
33 Avangrid Renewables, LLC Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
34 Avangrid Renewables, LLC Sierra Pacific Power Avista NF 7/8 M345 LOLO
35 Avangrid Renewables, LLC PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
36 Avangrid Renewables, LLC PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
37 Avangrid Renewables, LLC Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
38 Avista Corporation PacifiCorp East Avista NF 7/8 BRDY LOLO
39 Avista Corporation Avista Sierra Pacific Power NF 7/8 LOLO M345
40 Avista Corporation Sierra Pacific Power Avista NF 7/8 M345 LOLO
41 Avista Corporation Idaho Power Company Avista NF 7/8 WALLAWALLA LOLO
42 Benson Creek Windfarm, LLC NF 11
43 Black Hills Power Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
44 Black Hills Power Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
45 Black Hills Power Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JBSN
46 Black Hills Power Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
47 Bonneville Power Administration NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
48 Bonneville Power Administration NorthWestern/PacifiCorp East Bonneville Power Administration NF 7/8 BPAT.NWMT LAGRANDE
49 Bonneville Power Administration NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
50 Bonneville Power Administration NorthWestern/PacifiCorp East NF 7/8 BPAT.NWMT ANTE
51 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
52 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
53 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF 7/8 LAGRANDE LAGRANDE
54 Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
55 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE KPRT
56 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF 7/8 LAGRANDE OTEC
57 Bonneville Power Administration Avista PacifiCorp East NF 7/8 LOLO BORA
58 Bonneville Power Administration Avista Bonneville Power Administration NF 7/8 LOLO LAGRANDE
59 Bonneville Power Administration Avista Sierra Pacific Power NF 7/8 LOLO M345
60 Bonneville Power Administration PacifiCorp West PacifiCorp East SFP 7/8 SMLK BORA
61 Bonneville Power Administration PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
62 Brookfield Renewable Trading & Marketing NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
63 Brookfield Renewable Trading & Marketing PacifiCorp East Bonneville Power Administration SFP 7/8 BRDY LAGRANDE
64 Brookfield Renewable Trading & Marketing PacifiCorp East NorthWestern/PacifiCorp East SFP 7/8 BRDY BPAT.NWMT
65 Brookfield Renewable Trading & Marketing Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
66 Brookfield Renewable Trading & Marketing Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
67 Brookfield Renewable Trading & Marketing Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
68 Brookfield Renewable Trading & Marketing Sierra Pacific Power NorthWestern/PacifiCorp East SFP 7/8 M345 BPAT.NWMT
69 CCP OR Tenant 1, LLC (Thunderegg Solar Center)NF 11
70 ConocoPhillips Company Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
71 ConocoPhillips Company Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
72 ConocoPhillips Company Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
73 Durbin Creek Windfarm, LLC NF 11
74 Dynasty Power Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 AVAT.NWMT BRDY
75 Dynasty Power Inc.PacifiCorp East Idaho Power Company SFP 7/8 BORA IPCO
76 Dynasty Power Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
77 Dynasty Power Inc.PacifiCorp East Avista SFP 7/8 BORA LOLO
78 Dynasty Power Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
79 Dynasty Power Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA POP
80 Dynasty Power Inc.PacifiCorp East PacifiCorp West SFP 7/8 BORA H500
81 Dynasty Power Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
82 Dynasty Power Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
83 Dynasty Power Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
84 Dynasty Power Inc.NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
85 Dynasty Power Inc.PacifiCorp East PacifiCorp West NF 7/8 BRDY H500
86 Dynasty Power Inc.PacifiCorp East PacifiCorp West SFP 7/8 BRDY H500
87 Dynasty Power Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
88 Dynasty Power Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR BRDY
89 Dynasty Power Inc.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
90 Dynasty Power Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
91 Dynasty Power Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
92 Dynasty Power Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
93 Dynasty Power Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
94 Dynasty Power Inc.PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
95 Dynasty Power Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
96 Dynasty Power Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BRDY
97 Dynasty Power Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
98 Dynasty Power Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
99 Dynasty Power Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
100 Dynasty Power Inc.Avista PacifiCorp East NF 7/8 LOLO BORA
101 Dynasty Power Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
102 Dynasty Power Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
103 Dynasty Power Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
104 Dynasty Power Inc.Sierra Pacific Power NorthWestern/PacifiCorp East SFP 7/8 M345 BPAT.NWMT
105 Dynasty Power Inc.Sierra Pacific Power PacifiCorp West NF 7/8 M345 H500
106 Dynasty Power Inc.Sierra Pacific Power PacifiCorp West SFP 7/8 M345 H500
107 Dynasty Power Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 MLCK BRDY
108 Dynasty Power Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
109 Dynasty Power Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
110 Dynasty Power Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
111 Dynasty Power Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
112 Dynasty Power Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
113 Dynasty Power Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
114 EDF Trading North America, LLC NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
115 EDF Trading North America, LLC PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
116 EDF Trading North America, LLC PacifiCorp East PacifiCorp West NF 7/8 GSHN POP
117 EDF Trading North America, LLC PacifiCorp East PacifiCorp West SFP 7/8 GSHN POP
118 EDF Trading North America, LLC PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
119 EDF Trading North America, LLC PacifiCorp East PacifiCorp East NF 7/8 JEFF BRDY
120 EDF Trading North America, LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
121 EDF Trading North America, LLC Sierra Pacific Power Avista SFP 7/8 M345 LOLO
122 Energy Keepers, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
123 Energy Keepers, Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
124 Energy Keepers, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 GSHN MLCK
125 Energy Keepers, Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 MLCK
126 Energy Keepers, Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
127 Energy Keepers, Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
128 Exelon Generation Company, LLC NF 7/8
129 Guzman Energy Group LLC PacifiCorp East PacifiCorp East NF 7/8 BORA BRDY
130 Guzman Energy Group LLC PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
131 Guzman Energy Group LLC PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
132 Guzman Energy Group LLC PacifiCorp East Avista NF 7/8 BORA LOLO
133 Guzman Energy Group LLC PacifiCorp East Avista SFP 7/8 BORA LOLO
134 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
135 Guzman Energy Group LLC NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BORA
136 Guzman Energy Group LLC NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
137 Guzman Energy Group LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
138 Guzman Energy Group LLC PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
139 Guzman Energy Group LLC PacifiCorp East Avista NF 7/8 BRDY LOLO
140 Guzman Energy Group LLC PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
141 Guzman Energy Group LLC PacifiCorp East PacifiCorp West NF 7/8 BRDY HURR
142 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East SFP 7/8 BRDY BPAT.NWMT
143 Guzman Energy Group LLC PacifiCorp East PacifiCorp West NF 7/8 BRDY M500
144 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 HURR BRDY
145 Guzman Energy Group LLC PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
146 Guzman Energy Group LLC PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
147 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
148 Guzman Energy Group LLC PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
149 Guzman Energy Group LLC PacifiCorp East PacifiCorp West SFP 7/8 JBSN POP
150 Guzman Energy Group LLC PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
151 Guzman Energy Group LLC PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
152 Guzman Energy Group LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
153 Guzman Energy Group LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
154 Guzman Energy Group LLC Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
155 Guzman Energy Group LLC Avista PacifiCorp East NF 7/8 LOLO BORA
156 Guzman Energy Group LLC Avista Sierra Pacific Power NF 7/8 LOLO M345
157 Guzman Energy Group LLC Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
158 Guzman Energy Group LLC Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
159 Guzman Energy Group LLC Sierra Pacific Power Avista NF 7/8 M345 LOLO
160 Guzman Energy Group LLC Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
161 Guzman Energy Group LLC Sierra Pacific Power PacifiCorp West NF 7/8 M345 M500
162 Guzman Energy Group LLC Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 AVAT.NWMT
163 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 M500 BORA
164 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 M500 BRDY
165 Guzman Energy Group LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 MLCK M345
166 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
167 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
168 Guzman Energy Group LLC PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
169 Guzman Energy Group LLC Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
170 Idaho Winds LLC (Sawtooth Wind)NF 11
171 Idaho Wind Partners 1, LLC (Golden Valley Wind)NF 11
172 Jett Creek Windfarm, LLC NF 11
173 Lime Wind LLC NF 11
174 Macquarie Energy, LLC PacifiCorp East PacifiCorp East NF 7/8 BORA BRDY
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
175 Macquarie Energy, LLC PacifiCorp East PacifiCorp East SFP 7/8 BORA BRDY
176 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
177 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
178 Macquarie Energy, LLC PacifiCorp West Sierra Pacific Power NF 7/8 H500 M345
179 Macquarie Energy, LLC PacifiCorp West Sierra Pacific Power SFP 7/8 H500 M345
180 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
181 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
182 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power SFP 7/8 JEFF M345
183 Macquarie Energy, LLC PacifiCorp East Idaho Power Company SFP 7/8 JEFF IPCOEAST
184 Macquarie Energy, LLC Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
185 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
186 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BORA
187 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
188 Macquarie Energy, LLC Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
189 Macquarie Energy, LLC Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
190 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp West NF 7/8 M345 H500
191 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp West SFP 7/8 M345 H500
192 Macquarie Energy, LLC PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
193 Macquarie Energy, LLC Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
194 Mag Energy Solutions NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 AVAT.NWMT M345
195 Mag Energy Solutions Idaho Power Company PacifiCorp East NF 7/8 BGSY JEFF
196 Mag Energy Solutions PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
197 Mag Energy Solutions PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
198 Mag Energy Solutions Sierra Pacific Power PacifiCorp East NF 7/8 M345 GSHN
199 Mercuria Energy America, LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
200 Mercuria Energy America, LLC PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
201 Mercuria Energy America, LLC PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
202 Mercuria Energy America, LLC PacifiCorp East PacifiCorp West SFP 7/8 BRDY H500
203 Mercuria Energy America, LLC PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
204 Mercuria Energy America, LLC PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
205 Mercuria Energy America, LLC Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
206 Mercuria Energy America, LLC Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
207 Mercuria Energy America, LLC Sierra Pacific Power PacifiCorp West SFP 7/8 M345 H500
208 Mercuria Energy America, LLC PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
209 Mercuria Energy America, LLC Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
210 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 AVAT.NWMT BORA
211 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 AVAT.NWMT BORA
212 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 AVAT.NWMT M345
213 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 AVAT.NWMT M345
214 Morgan Stanley Capital Group Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
215 Morgan Stanley Capital Group Inc.PacifiCorp East Avista SFP 7/8 BORA LOLO
216 Morgan Stanley Capital Group Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
217 Morgan Stanley Capital Group Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 BORA M345
218 Morgan Stanley Capital Group Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
219 Morgan Stanley Capital Group Inc.PacifiCorp East PacifiCorp West SFP 7/8 BORA H500
220 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
221 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BORA
222 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
223 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
224 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
225 Morgan Stanley Capital Group Inc.PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
226 Morgan Stanley Capital Group Inc.PacifiCorp East PacifiCorp East SFP 7/8 BRDY BORA
227 Morgan Stanley Capital Group Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
228 Morgan Stanley Capital Group Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
229 Morgan Stanley Capital Group Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
230 Morgan Stanley Capital Group Inc.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
231 Morgan Stanley Capital Group Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
232 Morgan Stanley Capital Group Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
233 Morgan Stanley Capital Group Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
234 Morgan Stanley Capital Group Inc.PacifiCorp East Bonneville Power Administration NF 7/8 JEFF LAGRANDE
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
235 Morgan Stanley Capital Group Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
236 Morgan Stanley Capital Group Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 JEFF M345
237 Morgan Stanley Capital Group Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
238 Morgan Stanley Capital Group Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
239 Morgan Stanley Capital Group Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
240 Morgan Stanley Capital Group Inc.Bonneville Power Administration Sierra Pacific Power SFP 7/8 LAGRANDE M345
241 Morgan Stanley Capital Group Inc.Bonneville Power Administration NorthWestern/PacifiCorp East NF 7/8 LAGRANDE AVAT.NWMT
242 Morgan Stanley Capital Group Inc.Avista PacifiCorp East NF 7/8 LOLO BORA
243 Morgan Stanley Capital Group Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
244 Morgan Stanley Capital Group Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
245 Morgan Stanley Capital Group Inc.Idaho Power Company PacifiCorp East NF 7/8 LYPK BORA
246 Morgan Stanley Capital Group Inc.Idaho Power Company PacifiCorp East SFP 7/8 LYPK BORA
247 Morgan Stanley Capital Group Inc.Idaho Power Company PacifiCorp East NF 7/8 LYPK BRDY
248 Morgan Stanley Capital Group Inc.Idaho Power Company Avista NF 7/8 LYPK LOLO
249 Morgan Stanley Capital Group Inc.Idaho Power Company Sierra Pacific Power NF 7/8 LYPK M345
250 Morgan Stanley Capital Group Inc.Idaho Power Company Sierra Pacific Power SFP 7/8 LYPK M345
251 Morgan Stanley Capital Group Inc.Idaho Power Company NorthWestern/PacifiCorp East NF 7/8 LYPK BPAT.NWMT
252 Morgan Stanley Capital Group Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
253 Morgan Stanley Capital Group Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
254 Morgan Stanley Capital Group Inc.Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
255 Morgan Stanley Capital Group Inc.Sierra Pacific Power Avista NF 7/8 M345 LOLO
256 Morgan Stanley Capital Group Inc.Sierra Pacific Power Avista SFP 7/8 M345 LOLO
257 Morgan Stanley Capital Group Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
258 Morgan Stanley Capital Group Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
259 Morgan Stanley Capital Group Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
260 Morgan Stanley Capital Group Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
261 Morgan Stanley Capital Group Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
262 Morgan Stanley Capital Group Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
263 Nevada Power Company PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
264 Nevada Power Company Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
265 Nevada Power Company Avista Sierra Pacific Power NF 7/8 LOLO M345
266 Nevada Power Company Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
267 Northwestern Energy NF 7/8
268 Orchard Ranch Solar, LLC NF 11
269 PacifiCorp Inc.PacifiCorp East Avista SFP 7/8 BORA LOLO
270 PacifiCorp Inc.PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
271 PacifiCorp Inc.PacifiCorp East PacifiCorp East NF 7/8 BRDY BRDY
272 PacifiCorp Inc.PacifiCorp East PacifiCorp East SFP 7/8 BRDY BRDY
273 PacifiCorp Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
274 PacifiCorp Inc.PacifiCorp East Bonneville Power Administration SFP 7/8 BRDY LAGRANDE
275 PacifiCorp Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
276 PacifiCorp Inc.PacifiCorp East Idaho Power Company NF 7/8 JEFF BGSY
277 PacifiCorp Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
278 PacifiCorp Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
279 PacifiCorp Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
280 PacifiCorp Inc.Sierra Pacific Power Avista NF 7/8 M345 LOLO
281 PacifiCorp Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
282 PacifiCorp Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
283 PacifiCorp Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
284 Portland General Electric PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
285 Portland General Electric PacifiCorp East NorthWestern/PacifiCorp East SFP 7/8 BORA BPAT.NWMT
286 Portland General Electric PacifiCorp East PacifiCorp West SFP 7/8 BORA H500
287 Portland General Electric PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
288 Portland General Electric PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
289 Portland General Electric Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
290 Powerex Corporation PacifiCorp East PacifiCorp East NF 7/8 BORA BRDY
291 Powerex Corporation PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
292 Powerex Corporation PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
293 Powerex Corporation PacifiCorp East PacifiCorp West NF 7/8 BORA H500
294 Powerex Corporation PacifiCorp East PacifiCorp West SFP 7/8 BORA H500
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
295 Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
296 Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BORA
297 Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BRDY
298 Powerex Corporation NorthWestern/PacifiCorp East Bonneville Power Administration NF 7/8 BPAT.NWMT LAGRANDE
299 Powerex Corporation NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
300 Powerex Corporation PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
301 Powerex Corporation PacifiCorp East PacifiCorp East SFP 7/8 BRDY BORA
302 Powerex Corporation PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
303 Powerex Corporation PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
304 Powerex Corporation PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
305 Powerex Corporation PacifiCorp East PacifiCorp West NF 7/8 BRDY HURR
306 Powerex Corporation PacifiCorp East PacifiCorp West NF 7/8 BRDY H500
307 Powerex Corporation PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
308 Powerex Corporation PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
309 Powerex Corporation PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
310 Powerex Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
311 Powerex Corporation PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
312 Powerex Corporation PacifiCorp East PacifiCorp East NF 7/8 JEFF BRDY
313 Powerex Corporation PacifiCorp East Bonneville Power Administration NF 7/8 JEFF LAGRANDE
314 Powerex Corporation PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
315 Powerex Corporation Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
316 Powerex Corporation Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
317 Powerex Corporation Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JBSN
318 Powerex Corporation Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
319 Powerex Corporation Bonneville Power Administration Sierra Pacific Power SFP 7/8 LAGRANDE M345
320 Powerex Corporation Avista PacifiCorp East NF 7/8 LOLO BRDY
321 Powerex Corporation Avista PacifiCorp East SFP 7/8 LOLO BRDY
322 Powerex Corporation Avista Sierra Pacific Power NF 7/8 LOLO M345
323 Powerex Corporation Avista Sierra Pacific Power SFP 7/8 LOLO M345
324 Powerex Corporation Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
325 Powerex Corporation Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
326 Powerex Corporation Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
327 Powerex Corporation Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
328 Powerex Corporation Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
329 Powerex Corporation PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
330 Powerex Corporation PacifiCorp West PacifiCorp East SFP 7/8 SMLK BORA
331 Powerex Corporation PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
332 Powerex Corporation PacifiCorp West PacifiCorp East SFP 7/8 SMLK BRDY
333 Powerex Corporation PacifiCorp West PacifiCorp East SFP 7/8 SMLK JBSN
334 Powerex Corporation PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
335 Powerex Corporation PacifiCorp West Sierra Pacific Power SFP 7/8 SMLK M345
336 Powerex Corporation Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
337 Powerex Corporation Idaho Power Company PacifiCorp East SFP 7/8 WALLAWALLA BORA
338 Powerex Corporation Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
339 Powerex Corporation Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
340 Powerex Corporation Idaho Power Company Sierra Pacific Power SFP 7/8 WALLAWALLA M345
341 Prospector Windfarm, LLC NF 11
342 Rainbow Energy Marketing Corp.PacifiCorp East Avista SFP 7/8 BORA LOLO
343 Rainbow Energy Marketing Corp.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
344 Rainbow Energy Marketing Corp.PacifiCorp East Sierra Pacific Power NF 7/8 GSHN M345
345 Rainbow Energy Marketing Corp.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
346 Rainbow Energy Marketing Corp.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
347 Rainbow Energy Marketing Corp.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
348 Rainbow Energy Marketing Corp.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
349 Rainbow Energy Marketing Corp.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
350 Rainbow Energy Marketing Corp.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
351 Rainbow Energy Marketing Corp.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
352 Rainbow Energy Marketing Corp.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
353 Rainbow Energy Marketing Corp.Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BORA
354 Rainbow Energy Marketing Corp.Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
355 Rainbow Energy Marketing Corp.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
356 Rainbow Energy Marketing Corp.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
357 Rainbow Energy Marketing Corp.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
358 Rainbow Energy Marketing Corp.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
359 Rockland Wind Farm, LLC NF 11
360 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
361 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
362 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp West NF 7/8 BORA M500
363 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp West SFP 7/8 BORA M500
364 Shell Energy North America (US), L.P.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
365 Shell Energy North America (US), L.P.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
366 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
367 Shell Energy North America (US), L.P.PacifiCorp East Avista NF 7/8 BRDY LOLO
368 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
369 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
370 Shell Energy North America (US), L.P.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
371 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
372 Shell Energy North America (US), L.P.PacifiCorp West Bonneville Power Administration NF 7/8 HURR LAGRANDE
373 Shell Energy North America (US), L.P.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
374 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
375 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
376 Shell Energy North America (US), L.P.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
377 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp West NF 7/8 JBSN M500
378 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
379 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
380 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
381 Shell Energy North America (US), L.P.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
382 Shell Energy North America (US), L.P.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
383 Shell Energy North America (US), L.P.Bonneville Power Administration PacifiCorp East SFP 7/8 LAGRANDE BRDY
384 Shell Energy North America (US), L.P.Bonneville Power Administration Avista NF 7/8 LAGRANDE LOLO
385 Shell Energy North America (US), L.P.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
386 Shell Energy North America (US), L.P.Bonneville Power Administration Sierra Pacific Power SFP 7/8 LAGRANDE M345
387 Shell Energy North America (US), L.P.Avista PacifiCorp East NF 7/8 LOLO BORA
388 Shell Energy North America (US), L.P.Avista PacifiCorp East NF 7/8 LOLO BRDY
389 Shell Energy North America (US), L.P.Avista Sierra Pacific Power NF 7/8 LOLO M345
390 Shell Energy North America (US), L.P.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
391 Shell Energy North America (US), L.P.Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
392 Shell Energy North America (US), L.P.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
393 Shell Energy North America (US), L.P.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
394 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 M500 BORA
395 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
396 Shell Energy North America (US), L.P.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
397 Shell Energy North America (US), L.P.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
398 Shell Energy North America (US), L.P.Idaho Power Company Bonneville Power Administration NF 7/8 WALLAWALLA LAGRANDE
399 Shell Energy North America (US), L.P.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
400 Simcoe Solar, LLC NF 11
401 TEC Energy Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
402 TEC Energy Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
403 Tenaska Power Services PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
404 Tenaska Power Services NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
405 Tenaska Power Services PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
406 Tenaska Power Services PacifiCorp East Sierra Pacific Power NF 7/8 GSHN M345
407 Tenaska Power Services PacifiCorp East Sierra Pacific Power SFP 7/8 GSHN M345
408 Tenaska Power Services PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
409 Tenaska Power Services Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
410 Tenaska Power Services Avista Sierra Pacific Power NF 7/8 LOLO M345
411 Tenaska Power Services Idaho Power Company Sierra Pacific Power NF 7/8 MDSK M345
412 Tenaska Power Services Idaho Power Company Sierra Pacific Power SFP 7/8 MDSK M345
413 Tenaska Power Services Idaho Power Company PacifiCorp East SFP 7/8 MDSK GSHN
414 Tenaska Power Services Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
415 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
416 The Energy Authority, Inc.PacifiCorp East Avista NF 7/8 BORA LOLO
417 The Energy Authority, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
418 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA H500
419 The Energy Authority, Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
420 The Energy Authority, Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
421 The Energy Authority, Inc.NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BRDY
422 The Energy Authority, Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
423 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
424 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
425 The Energy Authority, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
426 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 BRDY M500
427 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 BRDY H500
428 The Energy Authority, Inc.PacifiCorp East PacifiCorp East SFP 7/8 GSHN BORA
429 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 GSHN M345
430 The Energy Authority, Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
431 The Energy Authority, Inc.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
432 The Energy Authority, Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
433 The Energy Authority, Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
434 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
435 The Energy Authority, Inc.PacifiCorp East Avista NF 7/8 JBSN LOLO
436 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
437 The Energy Authority, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
438 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 JEFF LAGRANDE
439 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
440 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 JEFF POP
441 The Energy Authority, Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
442 The Energy Authority, Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
443 The Energy Authority, Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
444 The Energy Authority, Inc.Avista PacifiCorp East NF 7/8 LOLO BORA
445 The Energy Authority, Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
446 The Energy Authority, Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
447 The Energy Authority, Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
448 The Energy Authority, Inc.Sierra Pacific Power Avista NF 7/8 M345 LOLO
449 The Energy Authority, Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
450 The Energy Authority, Inc.PacifiCorp West Sierra Pacific Power NF 7/8 POP M345
451 The Energy Authority, Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
452 The Energy Authority, Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
453 The Energy Authority, Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
454 The Energy Authority, Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
455 Thousand Springs Wind Park, LLC NF 11
456 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
457 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
458 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
459 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA H500
460 Transalta Energy Marketing (U.S.) Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
461 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
462 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
463 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
464 Transalta Energy Marketing (U.S.) Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
465 Transalta Energy Marketing (U.S.) Inc.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
466 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
467 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
468 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
469 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
470 Transalta Energy Marketing (U.S.) Inc.PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
471 Transalta Energy Marketing (U.S.) Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
472 Transalta Energy Marketing (U.S.) Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
473 Transalta Energy Marketing (U.S.) Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
474 Transalta Energy Marketing (U.S.) Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
475 Transalta Energy Marketing (U.S.) Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
476 Transalta Energy Marketing (U.S.) Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
477 Transalta Energy Marketing (U.S.) Inc.Sierra Pacific Power Avista NF 7/8 M345 LOLO
478 Transalta Energy Marketing (U.S.) Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
479 Transalta Energy Marketing (U.S.) Inc.Sierra Pacific Power PacifiCorp West NF 7/8 M345 H500
480 Transalta Energy Marketing (U.S.) Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
481 Transalta Energy Marketing (U.S.) Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
482 Transalta Energy Marketing (U.S.) Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
483 Transalta Energy Marketing (U.S.) Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
484 Utah Associated Municipal Power Systems PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
485 Vitol Inc.PacifiCorp East NorthWestern/PacifiCorp East SFP 7/8 BRDY BPAT.NWMT
486 Vitol Inc.Idaho Power Company PacifiCorp East SFP 7/8 MDSK BORA
487 Vitol Inc.Idaho Power Company PacifiCorp East SFP 7/8 MDSK BRDY
488 Willow Spring Windfarm, LLC NF 11
35 TOTAL
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Line
No.
Payment By (Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From (Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To (Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
1 (o)354,969 354,969 1,778,541 132,302 1,910,843
2 (p)207,448 207,448 1,608,818 143,854 1,752,672
3 (q)1,383,125 1,383,125 6,544,068 451,880 6,995,948
4 11,011 11,011 17,838 17,838
5 (r)221,749 221,749 80,260 80,260
6 (s)2,106 2,106 10,804 957 11,761
7 16,823 16,823 54,857 54,857
8 (t)1,211 1,211 856 856
9 21,242 21,242 15,012 15,012
10 0 0 5,920 5,920
11 0 0 3,180 3,180
12 1,261,867 1,261,867 4,387,671 4,387,671
13 956,922 956,922 3,752,215 3,752,215
14 1,506,139 1,506,139 7,319,612 7,319,612
15 39,620 39,620 3,056,240 3,056,240
16 148,976 148,976 3,025,980 3,025,980
17 464,181 464,181 3,025,980 3,025,980
18 15,720 15,720 2,148,446 2,148,446
19 240,762 240,762 4,554,480 4,554,480
20 8,198 8,198 76,115 76,115
21 0 0 13,151 13,151
22 0 0 5,664 5,664
23 0 0 5,664 5,664
24 0 0 5,568 5,568
25 0 0 7,775 7,775
26 0 0 7,775 7,775
27 150 150 1,539 1,539
28 428 428 4,391 4,391
29 150 150 1,539 1,539
30 1,556 1,556 15,963 15,963
31 90 90 923 923
32 30 30 308 308
33 2,794 2,794 28,664 28,664
34 175 175 1,795 1,795
35 371 371 3,806 3,806
36 201 201 2,062 2,062
37 300 300 3,078 3,078
38 680 680 5,728 5,728
39 575 575 4,843 4,843
40 301 301 2,535 2,535
41 1 1 8 8
42 0 0 2,871 2,871
43 365 365 2,142 2,142
44 57 57 335 335
45 62 62 364 364
46 460 460 2,700 2,700
47 7 7 37 37
48 46 46 245 245
49 135 135 720 720
50 110 110 586 586
51 673 673 3,587 3,587
52 76 76 405 405
53 9,203 9,203 49,057 49,057
54 12,489 12,489 66,573 66,573
55 4,963 4,963 26,455 26,455
56 2 2 11 11
57 7 7 37 37
58 8,119 8,119 43,278 43,278
59 2,038 2,038 10,864 10,864
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
60 3,899 3,899 20,784 20,784
61 4 4 21 21
62 89 89 724 724
63 248 248 2,018 2,018
64 408 408 3,320 3,320
65 13 13 106 106
66 180 180 1,465 1,465
67 152 152 1,237 1,237
68 456 456 3,711 3,711
69 0 0 192 192
70 63 63 388 388
71 215 215 1,324 1,324
72 738 738 4,546 4,546
73 0 0 2,871 2,871
74 348 348 3,682 3,682
75 200 200 2,116 2,116
76 400 400 4,232 4,232
77 4,205 4,205 44,494 44,494
78 353 353 3,735 3,735
79 123 123 1,301 1,301
80 1,950 1,950 20,633 20,633
81 592 592 6,264 6,264
82 50 50 529 529
83 413 413 4,370 4,370
84 622 622 6,581 6,581
85 825 825 8,729 8,729
86 3,972 3,972 42,028 42,028
87 649 649 6,867 6,867
88 131 131 1,386 1,386
89 1,039 1,039 10,994 10,994
90 774 774 8,190 8,190
91 40 40 423 423
92 1,168 1,168 12,359 12,359
93 9 9 95 95
94 651 651 6,888 6,888
95 294 294 3,111 3,111
96 13 13 138 138
97 380 380 4,021 4,021
98 352 352 3,725 3,725
99 695 695 7,354 7,354
100 854 854 9,036 9,036
101 399 399 4,222 4,222
102 1,010 1,010 10,687 10,687
103 272 272 2,878 2,878
104 144 144 1,524 1,524
105 1,200 1,200 12,697 12,697
106 2,910 2,910 30,791 30,791
107 31 31 328 328
108 2,570 2,570 27,194 27,194
109 185 185 1,958 1,958
110 11,163 11,163 118,117 118,117
111 3,851 3,851 40,748 40,748
112 400 400 4,232 4,232
113 3,709 3,709 39,245 39,245
114 19 19 1,265 1,265
115 24 24 1,598 1,598
116 83 83 5,525 5,525
117 2,159 2,159 143,717 143,717
118 26 26 1,731 1,731
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
119 75 75 4,992 4,992
120 294 294 19,571 19,571
121 400 400 26,627 26,627
122 1,174 1,174 16,267 16,267
123 2,600 2,600 36,025 36,025
124 235 235 3,256 3,256
125 15 15 208 208
126 425 425 5,889 5,889
127 240 240 3,325 3,325
128 0 0 153 153
129 474 474 5,228 5,228
130 901 901 9,937 9,937
131 749 749 8,260 8,260
132 880 880 9,705 9,705
133 48 48 529 529
134 90 90 993 993
135 2,559 2,559 28,222 28,222
136 505 505 5,569 5,569
137 985 985 10,863 10,863
138 725 725 7,996 7,996
139 198 198 2,184 2,184
140 594 594 6,551 6,551
141 126 126 1,390 1,390
142 275 275 3,033 3,033
143 114 114 1,257 1,257
144 50 50 551 551
145 148 148 1,632 1,632
146 400 400 4,411 4,411
147 26 26 287 287
148 416 416 4,588 4,588
149 263 263 2,900 2,900
150 114 114 1,257 1,257
151 568 568 6,264 6,264
152 576 576 6,352 6,352
153 60 60 662 662
154 940 940 10,367 10,367
155 508 508 5,602 5,602
156 1,921 1,921 21,186 21,186
157 306 306 3,375 3,375
158 3,444 3,444 37,982 37,982
159 804 804 8,867 8,867
160 969 969 10,687 10,687
161 162 162 1,787 1,787
162 100 100 1,103 1,103
163 161 161 1,776 1,776
164 100 100 1,103 1,103
165 225 225 2,481 2,481
166 25 25 276 276
167 151 151 1,665 1,665
168 1,146 1,146 12,639 12,639
169 270 270 2,978 2,978
170 0 0 5,568 5,568
171 0 0 2,599 2,599
172 0 0 2,871 2,871
173 0 0 100 100
174 112 112 300 300
175 1,600 1,600 4,284 4,284
176 20 20 54 54
177 417 417 1,116 1,116
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
178 887 887 2,375 2,375
179 1,474 1,474 3,946 3,946
180 449 449 1,202 1,202
181 4,380 4,380 11,727 11,727
182 53,437 53,437 143,072 143,072
183 200 200 535 535
184 164 164 439 439
185 1,381 1,381 3,697 3,697
186 1,860 1,860 4,980 4,980
187 6,681 6,681 17,888 17,888
188 603 603 1,614 1,614
189 6,192 6,192 16,578 16,578
190 243 243 651 651
191 6,464 6,464 17,307 17,307
192 125 125 335 335
193 50 50 134 134
194 2 2 27 27
195 1 1 14 14
196 255 255 3,472 3,472
197 303 303 4,125 4,125
198 1 1 14 14
199 54 54 411 411
200 2,153 2,153 16,402 16,402
201 18,397 18,397 140,151 140,151
202 4,194 4,194 31,951 31,951
203 408 408 3,108 3,108
204 400 400 3,047 3,047
205 3,450 3,450 26,283 26,283
206 1,944 1,944 14,810 14,810
207 1,193 1,193 9,088 9,088
208 27,483 27,483 209,370 209,370
209 56,859 56,859 433,161 433,161
210 3,001 3,001 8,847 8,847
211 6,846 6,846 20,182 20,182
212 3,203 3,203 9,443 9,443
213 22,034 22,034 64,957 64,957
214 4,472 4,472 13,184 13,184
215 17,666 17,666 52,080 52,080
216 568 568 1,674 1,674
217 7,187 7,187 21,188 21,188
218 1,049 1,049 3,093 3,093
219 1 1 3 3
220 1,384 1,384 4,080 4,080
221 8,770 8,770 25,854 25,854
222 517 517 1,524 1,524
223 65,101 65,101 191,921 191,921
224 131,930 131,930 388,936 388,936
225 875 875 2,580 2,580
226 13,302 13,302 39,215 39,215
227 1,027 1,027 3,028 3,028
228 22,140 22,140 65,270 65,270
229 52,629 52,629 155,153 155,153
230 100 100 295 295
231 78 78 230 230
232 1,209 1,209 3,564 3,564
233 13,059 13,059 38,499 38,499
234 865 865 2,550 2,550
235 71,722 71,722 211,440 211,440
236 3,814 3,814 11,244 11,244
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
237 3,932 3,932 11,592 11,592
238 962 962 2,836 2,836
239 80,985 80,985 238,748 238,748
240 1,802 1,802 5,312 5,312
241 152 152 448 448
242 17,630 17,630 51,974 51,974
243 44 44 130 130
244 21,779 21,779 64,205 64,205
245 216 216 637 637
246 13,571 13,571 40,008 40,008
247 365 365 1,076 1,076
248 9 9 27 27
249 6,164 6,164 18,172 18,172
250 163,738 163,738 482,707 482,707
251 144 144 425 425
252 1,275 1,275 3,759 3,759
253 15,760 15,760 46,461 46,461
254 24,651 24,651 72,672 72,672
255 275 275 811 811
256 2,091 2,091 6,164 6,164
257 1,354 1,354 3,992 3,992
258 61,410 61,410 181,040 181,040
259 18,714 18,714 55,170 55,170
260 137,948 137,948 406,677 406,677
261 26 26 77 77
262 4,598 4,598 13,555 13,555
263 200 200 2,887 2,887
264 19 19 274 274
265 300 300 4,330 4,330
266 56 56 808 808
267 0 0 275 275
268 0 0 96 96
269 2,328 2,328 27,092 27,092
270 3,081 3,081 35,855 35,855
271 7,843 7,843 91,272 91,272
272 3,212 3,212 37,379 37,379
273 35,912 35,912 417,924 417,924
274 22,259 22,259 259,038 259,038
275 1,728 1,728 20,110 20,110
276 56 56 652 652
277 450 450 5,237 5,237
278 100 100 1,164 1,164
279 298 298 3,468 3,468
280 1 1 12 12
281 104 104 1,210 1,210
282 124 124 1,443 1,443
283 13,482 13,482 156,896 156,896
284 28,702 28,702 304,186 304,186
285 836 836 8,860 8,860
286 70 70 742 742
287 7,216 7,216 76,476 76,476
288 64 64 678 678
289 890 890 9,432 9,432
290 6,832 6,832 45,604 45,604
291 4,176 4,176 27,875 27,875
292 849 849 5,667 5,667
293 40 40 267 267
294 915 915 6,108 6,108
295 98 98 654 654
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
296 441 441 2,944 2,944
297 1,234 1,234 8,237 8,237
298 58 58 387 387
299 1,040 1,040 6,942 6,942
300 915 915 6,108 6,108
301 3,905 3,905 26,066 26,066
302 2,710 2,710 18,090 18,090
303 3,243 3,243 21,647 21,647
304 16,200 16,200 108,137 108,137
305 21 21 140 140
306 60 60 401 401
307 775 775 5,173 5,173
308 29 29 194 194
309 3,040 3,040 20,292 20,292
310 67 67 447 447
311 166 166 1,108 1,108
312 38 38 254 254
313 397 397 2,650 2,650
314 63 63 421 421
315 8,230 8,230 54,936 54,936
316 455 455 3,037 3,037
317 10 10 67 67
318 5,270 5,270 35,178 35,178
319 527 527 3,518 3,518
320 100 100 668 668
321 39,576 39,576 264,174 264,174
322 1,019 1,019 6,802 6,802
323 6,356 6,356 42,427 42,427
324 231 231 1,542 1,542
325 61 61 407 407
326 63,200 63,200 421,867 421,867
327 96 96 641 641
328 1,187 1,187 7,923 7,923
329 34,960 34,960 233,362 233,362
330 70,851 70,851 472,938 472,938
331 312 312 2,083 2,083
332 2,449 2,449 16,347 16,347
333 1,235 1,235 8,244 8,244
334 9,418 9,418 62,866 62,866
335 6,951 6,951 46,399 46,399
336 59,192 59,192 395,113 395,113
337 579 579 3,865 3,865
338 27 27 180 180
339 2,839 2,839 18,951 18,951
340 3,108 3,108 20,746 20,746
341 0 0 2,871 2,871
342 924 924 9,664 9,664
343 59 59 617 617
344 105 105 1,098 1,098
345 134 134 1,401 1,401
346 279 279 2,918 2,918
347 752 752 7,865 7,865
348 985 985 10,302 10,302
349 135 135 1,412 1,412
350 559 559 5,847 5,847
351 30 30 314 314
352 100 100 1,046 1,046
353 600 600 6,275 6,275
354 400 400 4,184 4,184
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
355 5,400 5,400 56,478 56,478
356 7,200 7,200 75,304 75,304
357 1,995 1,995 20,866 20,866
358 6,512 6,512 68,108 68,108
359 0 0 6,343 6,343
360 1,154 1,154 16,207 16,207
361 2,444 2,444 34,324 34,324
362 68 68 955 955
363 660 660 9,269 9,269
364 40 40 562 562
365 1,898 1,898 26,656 26,656
366 5,962 5,962 83,733 83,733
367 227 227 3,188 3,188
368 5,037 5,037 70,742 70,742
369 2,529 2,529 35,518 35,518
370 104 104 1,461 1,461
371 418 418 5,871 5,871
372 24 24 337 337
373 210 210 2,949 2,949
374 2,899 2,899 40,715 40,715
375 3,898 3,898 54,745 54,745
376 210 210 2,949 2,949
377 323 323 4,536 4,536
378 65 65 913 913
379 209 209 2,935 2,935
380 514 514 7,219 7,219
381 262 262 3,680 3,680
382 1,645 1,645 23,103 23,103
383 123 123 1,727 1,727
384 50 50 702 702
385 35,172 35,172 493,969 493,969
386 10,146 10,146 142,494 142,494
387 450 450 6,320 6,320
388 1,528 1,528 21,460 21,460
389 5,857 5,857 82,258 82,258
390 497 497 6,980 6,980
391 243 243 3,413 3,413
392 10,660 10,660 149,713 149,713
393 1,170 1,170 16,432 16,432
394 30 30 421 421
395 3,069 3,069 43,102 43,102
396 7,099 7,099 99,701 99,701
397 1,656 1,656 23,258 23,258
398 32 32 449 449
399 29,239 29,239 410,644 410,644
400 0 0 576 576
401 23 23 2,144 2,144
402 4 4 373 373
403 44 44 146 146
404 192 192 639 639
405 46,445 46,445 154,599 154,599
406 32 32 107 107
407 924 924 3,076 3,076
408 5,548 5,548 18,467 18,467
409 265 265 882 882
410 384 384 1,278 1,278
411 532 532 1,771 1,771
412 1,339 1,339 4,457 4,457
413 15,144 15,144 50,409 50,409
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
414 912 912 3,036 3,036
415 842 842 4,794 4,794
416 600 600 3,416 3,416
417 983 983 5,597 5,597
418 175 175 996 996
419 470 470 2,676 2,676
420 1,143 1,143 6,508 6,508
421 141 141 803 803
422 1,607 1,607 9,151 9,151
423 1,100 1,100 6,264 6,264
424 215 215 1,224 1,224
425 525 525 2,989 2,989
426 714 714 4,066 4,066
427 20 20 114 114
428 22 22 125 125
429 57 57 325 325
430 25 25 142 142
431 75 75 427 427
432 11 11 63 63
433 31 31 177 177
434 161 161 917 917
435 50 50 285 285
436 152 152 866 866
437 9 9 51 51
438 75 75 427 427
439 757 757 4,310 4,310
440 96 96 547 547
441 778 778 4,430 4,430
442 655 655 3,730 3,730
443 6,774 6,774 38,572 38,572
444 390 390 2,221 2,221
445 298 298 1,697 1,697
446 1,303 1,303 7,419 7,419
447 22,061 22,061 125,619 125,619
448 350 350 1,993 1,993
449 1,108 1,108 6,309 6,309
450 26 26 148 148
451 1,326 1,326 7,550 7,550
452 2,967 2,967 16,895 16,895
453 1,193 1,193 6,793 6,793
454 6,558 6,558 37,342 37,342
455 0 0 42,946 42,946
456 1,446 1,446 9,206 9,206
457 15 15 95 95
458 58 58 369 369
459 1,469 1,469 9,352 9,352
460 30 30 191 191
461 194 194 1,235 1,235
462 7 7 45 45
463 120 120 764 764
464 73 73 465 465
465 378 378 2,406 2,406
466 149 149 949 949
467 515 515 3,279 3,279
468 1,020 1,020 6,494 6,494
469 550 550 3,501 3,501
470 763 763 4,858 4,858
471 2,257 2,257 14,369 14,369
472 100 100 637 637
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
473 6,001 6,001 38,204 38,204
474 72 72 458 458
475 114 114 726 726
476 5,885 5,885 37,466 37,466
477 42 42 267 267
478 60 60 382 382
479 51 51 325 325
480 6,048 6,048 38,504 38,504
481 918 918 5,844 5,844
482 26,183 26,183 166,686 166,686
483 2,298 2,298 14,630 14,630
484 4,426 4,426 28,150 28,150
485 244 244 475 475
486 49 49 95 95
487 244 244 475 475
488 0 0 2,871 2,871
35 0 9,081,201 9,081,201 9,942,231 44,982,539 0 54,924,770
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: PaymentByCompanyOrPublicAuthority
(b) Concept: PaymentByCompanyOrPublicAuthority
(c) Concept: PaymentByCompanyOrPublicAuthority
(d) Concept: PaymentByCompanyOrPublicAuthority
(e) Concept: PaymentByCompanyOrPublicAuthority
(f) Concept: PaymentByCompanyOrPublicAuthority
(g) Concept: PaymentByCompanyOrPublicAuthority
(h) Concept: PaymentByCompanyOrPublicAuthority
(i) Concept: RateScheduleTariffNumber
(j) Concept: RateScheduleTariffNumber
(k) Concept: RateScheduleTariffNumber
(l) Concept: RateScheduleTariffNumber
(m) Concept: RateScheduleTariffNumber
(n) Concept: RateScheduleTariffNumber
(o) Concept: BillingDemand
(p) Concept: BillingDemand
(q) Concept: BillingDemand
(r) Concept: BillingDemand
(s) Concept: BillingDemand
(t) Concept: BillingDemand
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
TRANSFER OF ENERGY TRANSFER OF ENERGY
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
MegaWatt Hours Received
(c)
MegaWatt Hours Delivered
(d)
1 Avangrid Renewables, LLC.(a)
SFP
2 Avista Corp. - WWP Div.(b)
LFP 216,216 216,216
3 Avista Corp. - WWP Div.NF 671 671
4 Avista Corp. - WWP Div.SFP 42,153 42,153
5 Avista Corp. - WWP Div.(c)
SFP
6 Avista Corp. - WWP Div.(d)
OS
7 Bonneville Power Administration (e)
LFP 150,816 150,816
8 Bonneville Power Administration SFP 135,751 135,751
9 Bonneville Power Administration NF 2,650 2,650
10 Bonneville Power Administration (f)
OS
11 Bonneville Power Administration (g)
OS
12 Bonneville Power Administration (h)
OS 93,948 93,948
13 Bonneville Power Administration (i)
OS 16,757 16,757
14 Bonneville Power Administration (j)
OS 8,202 8,202
15 Bonneville Power Administration (k)
OS 2,736 2,736
16 Bonneville Power Administration
(l)
OS 1,868 1,868
17 Bonneville Power Administration (m)
OS 800 800
18 NorthWestern Energy SFP 17,422 17,422
19 NorthWestern Energy NF 2,540 2,540
20 NorthWestern Energy (n)
OS
21 NorthWestern Energy
(o)
OS
22 NorthWestern Energy (p)
OS
23 NV Energy NF 1,747 1,747
24 NV Energy SFP 2,676 2,676
25 NV Energy (q)
OS
26 PacifiCorp Inc.
(r)
LFP 37,305 37,305
27 PacifiCorp Inc.NF 148,380 148,380
28 PacifiCorp Inc.SFP 1,729 1,729
29 PacifiCorp Inc.(s)
OS
30 PacifiCorp Inc.(t)
OS
31 PacifiCorp Inc.(u)
OS
32 Puget Sound Energy
(v)
SFP
33 Seattle City Light (w)
SFP
34 Snohomish County PUD (x)
SFP
35 Tacoma Power (y)
SFP
TOTAL 884,367 884,367
FERC FORM NO. 1 (REV. 02-04)
Page 332
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
Line
No.
Demand Charges ($)
(e)
Energy Charges ($)
(f)
Other Charges ($)
(g)
Total Cost of Transmission ($)
(h)
1 1,600 1,600
2 1,824,500 1,824,500
3 10,393 10,393
4 172,923 172,923
5 2,500 2,500
6 (929)(929)
7 1,220,525 1,220,525
8 314,268 314,268
9 13,010 13,010
10 294,223 294,223
11 6,708 6,708
12
13
14
15
16
17
18 116,775 116,775
19 15,836 15,836
20 3,805 3,805
21 26 26
22 (6,345)(6,345)
23 20,610 20,610
24 15,700 15,700
25 5,162 5,162
26 809,439 809,439
27 1,780,072 1,780,072
28 3,931 3,931
29 166,717 166,717
30 (37,103)(37,103)
31 (425)(425)
32 15,912 15,912
33 34,915 34,915
34 210,756 210,756
35 7,052 7,052
0 6,590,717 431,839 7,022,556
FERC FORM NO. 1 (REV. 02-04)
Page 332
FOOTNOTE DATA
(a) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider
(b) Concept: StatisticalClassificationCode
Contract Expiration Date 04/30/2026
(c) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider
(d) Concept: StatisticalClassificationCode
Credit of Imbalance Penalty Charges
(e) Concept: StatisticalClassificationCode
There are 3 contracts with Expiration Dates of 12/31/2021 and 12/31/2025
(f) Concept: StatisticalClassificationCode
Ancillary services
(g) Concept: StatisticalClassificationCode
Spinning/Supplemental Reserves
(h) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider for Snohomish
(i) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider for Seattle City Light
(j) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider for Puget Sound Energy
(k) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider for Tacoma Power
(l) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider for Avista Corp
(m) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider for Avangrid Renewables
(n) Concept: StatisticalClassificationCode
Ancillary services
(o) Concept: StatisticalClassificationCode
Schedule 3A - non-VER
(p) Concept: StatisticalClassificationCode
2019-2020 FERC Rate Refund
(q) Concept: StatisticalClassificationCode
Ancillary services
(r) Concept: StatisticalClassificationCode
Contract Expiration Date 5/31/2024
(s) Concept: StatisticalClassificationCode
Ancillary services
(t) Concept: StatisticalClassificationCode
2019 LFT Refund -476, 2020 LFP Refund -36,631 Line Total -37,104
(u) Concept: StatisticalClassificationCode
2020 Unreserved Use Refund
(v) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider
(w) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider
(x) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider
(y) Concept: StatisticalClassificationCode
Capacity reassignment, BPAT is provider
FERC FORM NO. 1 (REV. 02-04)
Page 332
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.Description
(a)
Amount
(b)
1 Industry Association Dues 577,192
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities (a)1,989,834
5 Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6 Director Fees and Expenses
7 BOLANO, ODETTE 91,080
8 CARLILE, THOMAS 85,140
9 DAHL, RICHARD J 191,235
10 Darrel Anderson 79,200
11 ELG, ANNETTE G 95,700
12 JIBSON, RONALD W 86,130
13 JOHANSEN, JUDITH A 93,060
14 JOHNSON, DENNIS L 105,600
15 KING, CHRISTINE 42,075
16 NAVARRO, RICHARD 107,910
17 PETERS, MARK 80,520
18 Travel & Lodging 46,283
19 Corporate Memberships and Subscriptions
20 ASSOCIATED TAXPAYERS OF I 22,000
21 BANNOCK DEVELOPMENT CORPO 9,000
22 BOISE METRO CHAMBER OF CO 13,893
23 BOISE VALLEY ECONOMIC PARTNERS 20,000
24 BUSINESS PLUS INC 5,000
25 CEATI INTERNATIONAL INC 68,150
26 CHARTWELL, INC 53,303
27 E Source 19,913
28 ELECTRIC POWER RESEARCH 14,133
29 GRID FORWARD 7,500
30 NACD ONLINE 11,770
31 NATIONAL HYDROPOWER ASSOC 45,062
32 NORTH AMERICAN ENERGY STANDARD 8,000
33 OREGON STATE UNIVERSITY 15,000
34 PACIFIC NW UTILITIES 53,789
35 SOUTHERN IDAHO ECONOMIC 5,000
36 Chamber of Commerce and Other Civic Organizations 28,049
37 Misc. Memberships or Subscriptions under $5000 19,975
46 TOTAL 4,090,496
FERC FORM NO. 1 (ED. 12-94)
Page 335
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: PublicationAndDistributionExpensesForSecuritiesToStockholders
Pub & Distr info to Stckholders Purpose Amount
BANK OF NEW YORK Misc Expense 7,267
BLOOMBERG FINANCE LP Misc Expense 25,488
BROADRIDGE FINANCIAL SOLUTIONS Misc Expense 101,212
BUSINESS WIRE INC Misc Expense 10,890
D F KING & COMPANY INC Misc Expense 29,402
DEUTSCHE BANK TRUST CO Broker Fees 30,000
EQ SHAREOWNER SERVICES MGMT Expense 103,929
Fees & Training Related to Stockholder Services Misc Expense 5,604
MARKIT NORTH AMERICA INC Misc Expense 56,430
MODERN NETWORKS IR, LLC Misc Expense 11,821
MOODY'S ANALYTICS INC Financial Software 39,759
NASDAQ CORPORATE SOLUTIONS LLC MGMT Expense 31,092
NEW YORK STOCK EXCHANGE I Listing Service 70,133
PAYROLL RELATED Misc Expense 196,077
Q4 INC Misc Expense 24,750
RIVEL RESEARCH GROUP INC MGMT Expense 15,840
SIDOTI & COMPANY LLC Misc Expense 5,400
Stock Based Compensation Misc Expense 1,197,866
Travel Expense-Stock Related Misc Expense 6,866
Misc Expense for Disfor Pub & Distr less than $5000 Misc Expense 20,008
1,989,834
FERC FORM NO. 1 (ED. 12-94)
Page 335
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
A. Summary of Depreciation and Amortization Charges A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation
and Amortization Charges
Line
No.
Functional Classification
(a)
Depreciation Expense (Account
403)
(b)
Depreciation Expense for Asset
Retirement Costs (Account 403.1)
(c)
Amortization of Limited Term
Electric Plant (Account 404)
(d)
Amortization of Other Electric Plant
(Acc 405)
(e)
Total
(f)
1 Intangible Plant 8,739,017 8,739,017
2 Steam Production Plant 43,797,037 43,797,037
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 19,142,557 19,142,557
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 16,073,768 16,073,768
7 Transmission Plant 24,368,971 24,368,971
8 Distribution Plant 45,252,952 45,252,952
9 Regional Transmission and Market Operation
10 General Plant 16,811,412 16,811,412
11 Common Plant-Electric
12 TOTAL (a)165,446,697 8,739,017 174,185,714
FERC FORM NO. 1 (REV. 12-03)
Page 336-337
B. Basis for Amortization Charges
C. Factors Used in Estimating Depreciation Charges
Line
No.
Account No.
(a)
Depreciable Plant Base (in
Thousands)
(b)
Estimated Avg. Service Life
(c)
Net Salvage
(Percent)
(d)
Applied Depr. Rates
(Percent)
(e)
Mortality Curve Type
(f)
Average Remaining Life
(g)
12 (b)
31020 649 75 years 4.399%R4.0 17 years, 11 months
13 31100 120,946 100 years (9)%3.425%S0.5 17 years, 11 months
14 31210 196,319 70 years (5)%3.479%S1 18 years, 1 month
15 31220 449,330 53 years (8)%4.918%R1.5 17 years
16 31230 2,504 35 years 10%1.238%R3.0 13 years, 6 months
17 31400 140,616 45 years (7)%5.576%S0.5 16 years, 6 months
18 31500 54,102 60 years (3)%3.764%S1.5 16 years, 10 months
19 31600 12,491 35 years 2%6.633%S0 14 years, 7 months
20 31610 509 13 years 15%7.717%L2.0 5 years, 5 months
21 31640 240 13 years 15%0.255%L2.0
22 31650 1,122 13 years 15%5.727%L2.0 11 years, 10 months
23 31660 45 13.746%
24 31670 401 21 years 15%0.35%S1 12 years, 2 months
25 31680 4,330 20 years 25%4.233%O1 17 years, 10 months
26 31690 14 35 years 15%2.43%S1 30 years, 7 months
27 31700 26,540
28 Sub-Total 1,010,158
29 33100 245,329 120 years (25)%2.08%R2.5 35 years, 10 months
30 33210 19,461 120 years (20)%0.98%S1.5 46 years, 2 months
31 33220 275,959 120 years (20)%1.8%S1.5 31 years, 2 months
32 33230 5,472 1.15%Square 55 years, 1 month
33 33300 340,646 100 years (10)%1.92%R2.5 30 years, 7 months
34 33400 68,319 65 years (10)%2.82%R1.5 27 years, 10 months
35 33500 28,501 90 years (5)%2.18%R2.0 31 years, 2 months
36 33510 180 15 years 7.92%Square 7 years, 11 months
37 33520 42 20 years 0.8%Square 9 years, 2 months
38 33530 530 5 years 14.42%Square 2 years, 6 months
39 33600 14,790 100 years 2.58%R3.0 22 years, 8 months
40 Sub-Total 999,229
41 34100 154,586 2.72%Square 32 years, 10 months
42 34110 3 25 years 4%
43 34200 10,446 50 years 2.81%S2.5 28 years, 8 months
44 34300 221,427 40 years 3.18%R2.0 26 years, 0 months
45 34400 66,599 50 years 2.45%S2.0 28 years, 5 months
46 (c)
34410 79 25 years 4%
47 34500 92,082 55 years 2.91%R2.0 29 years, 4 months
48 34600 6,890 35 years 3.24%R2.5 24 years
49 34610 13 25 years 4%
50 Sub-Total 552,125
51 35020 35,471 100 years 0.89%R4.0 85 years, 2 months
52 35022 254 30 years 3.33%
53 35200 87,474 65 years (33)%1.88%R3.0 53 years, 2 months
54 35300 470,126 52 years (10)%1.97%S0.5 42 years
55 35400 231,331 80 years (10)%1.07%R4.0 71 years, 1 month
56 35500 220,735 65 years (80)%2.64%R1.5 53 years, 11 months
57 35510 3,428 10 years 10%
58 35600 256,042 74 years (50)%1.87%R1.5 62 years, 4 months
59 35900 390 65 years 0.91%R2.5 33 years, 4 months
60 Sub-Total 1,305,251
61 36022 874 30 years 3.33%
62 36100 52,170 70 years (50)%2.17%R3 54 years, 5 months
63 36200 301,418 55 years (6)%1.85%R1.5 42 years, 11 months
64 36400 293,005 58 years (50)%2.17%R1.5 44 years, 1 month
65 36410 14,119 12 years 8.34%
66 36500 152,119 49 years (30)%2.65%R1.0 34 years, 5 months
67 36600 53,352 65 years (25)%1.89%R2.5 49 years, 1 month
68 36700 313,609 50 years (11)%1.9%R1.5 39 years, 5 months
69 36800 683,919 42 years (7)%2.17%R0.5 34 years, 10 months
70 36900 66,365 55 years (40)%1.58%R1.5 43 years, 5 months
71 37000 19,927 30 years (5)%2.05%O1.0 25 years, 8 months
72 37010 90,141 18 years (5)%5.39%R1.5 14 years
73 37120 5,285 21 years (5)%2.88%R1.0 14 years, 8 months
74 37320 5,558 40 years (30)%1.73%R1.0 29 years
75 37400 0
76 Sub-Total 2,051,861
77 39011 32,861 90 years (3)%2.08%S1.0 33 years, 2 months
78 39012 108,278 55 years (3)%2.11%R2.0 38 years, 10 months
79 39110 13,537 20 years 4%Square 12 years, 4 months
80 39120 26,228 5 years 20%Square 2 years, 8 months
81 39121 3,239 8 years 12.5%Square 3 years, 6 months
82 39210 788 13 years 15%7.07%L2.0 9 years, 4 months
83 39230 4,563 15 years 40%4.13%S2.5 9 years, 8 months
84 39240 28,605 13 years 15%6.2%L2.0 8 years, 6 months
85 39250 1,895 13 years 15%6.34%L2.0 8 years, 11 months
86 39260 54,935 21 years 15%3.95%S1.0 14 years
87 39270 10,445 21 years 15%4.16%S1.0 12 years, 4 months
88 39290 8,061 35 years 15%2.24%S1.0 24 years, 4 months
89 39300 4,279 25 years 4%Square 17 years, 5 months
90 39400 12,357 20 years 5%Square 12 years, 5 months
91 39500 14,779 20 years 5%Square 10 years, 7 months
92 39600 23,928 20 years 25%2.97%O1.0 16 years, 8 months
93 39710 5,367 15 years 6.67%Square 4 years, 8 months
94 39720 24,385 15 years 6.67%Square 8 years, 1 month
95 39730 26,180 15 years 6.67%Square 9 years, 8 months
96 39740 20,304 15 years 6.02%Square 13 years, 1 month
97 39750 5,106 20 years 5%
98 39800 10,210 15 years 6.67%Square 8 years, 7 months
99 Sub-Total 440,330
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments
Page 336 Section B: Basis for Amortization Charges
Account 404 - Basis used to compute charges:
Balance to be Balance to be Remaining
Amortized 2021 Amortized months of
1/1/2021 Amortization 12/31/2021 Amort 12/31/21
(1) Shoshone Bannock Agreement 24,000 12,000 12,000 12
(2) Mid Snake Relicensing 7,168,732 523,123 6,645,609 -
(3) Swan Falls Relicensing 4,114,672 189,908 3,924,764 248
(4) Software 20,888,500 7,483,895 18,784,301 -
(5) Shoshone Bannock ROW 2,020,602 287,899 1,732,703 72
(6) FERC Compliance Costs 6,175,005 153,247 8,958,816 -
(7) Radio Frequency - Spectrum 3,424,089 88,946 3,335,143 450
Total 43,815,600 8,739,018 43,393,336
(1) Shoshone-Bannock Tribe License & Use Agreement. New five year advance payment starting January 2018, with a
December 31, 2022 termination date.
(2) Middle Snake Relicensing Costs (Amortized over a 30 year license period; licenses expire July 31, 2034 and February 28, 2035).
(3) Swan Falls Relicensing Costs (Amortized over a 30 year license period, license expires August 31, 2042).
(4) Computer Software packages (Amortized over a 62 month period).
(5) Shoshone-Bannock Right of Way (Termination date December 31, 2027).
(6) FERC License Compliance Costs (amortized over the term of the applicable FERC Licenses)
(7) Radio Frequency Spectrum (Amortized over a 40 year period beginning July 2019)
(b) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
Page 337:
SchedulePage: 337Line: 12 to 113 Column: c, d,e, g
Steam,hydro, and other production depreciation and amortization of certain electric plant is maintained by plantlocation. Effective April 1,1993 theforecast life span methodof life analysis using an interim retirement rate was utilized to develop all production plant rates. Rates, service lives, net salvage
andremaining lives indicated areon a composite basis. Effective April 1,1993 all depreciable plant is being
depreciated using the straight-lineremaining life method.
SchedulePage: 337Line: 12 to 26 Column: c, d, f,g
Plant accounts 31020 through 31650 and31670 through 31690 arepresented for Jim Bridger facility only.This data is provided by the most recent depreciation study; Jim Bridgerwas the only thermal production facility included in the depreciation study. Plant account 31660 is associated with Valmyfacility
only. Valmy was not part ofthe 2016 depreciation study, as Valmy has been reviewed for decommissioningwithin regulatory order 33771. There isno data for estimated service life, net salvage percentage, or mortalitycurve.
SchedulePage: 337Line: 12 to 26 Column: e
Anaverage plant balance was used in computing theseratesby plant account.
(c) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
Page 337 Line 46:
Schedule Page: 337Line: 46, 50, 53, 106 Column: c, d, f, g
Plant accounts 34110, 34410, 34610 and39750 were not included in the last depreciation study and have not beensubject to depreciation study review.
FERC FORM NO. 1 (REV. 12-03)
Page 336-337
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
REGULATORY COMMISSION EXPENSES
EXPENSES INCURRED
DURING YEAR
EXPENSES
INCURRED
DURING
YEAR
CURRENTLY CHARGED TO
CURRENTLY
CHARGED
TO
Line
No.
Description (Furnish name of regulatory commission or
body the docket or case number and a description of the
case)
(a)
Assessed by Regulatory
Commission
(b)
Expenses of Utility
(c)
Total Expenses for Current Year
(d)
Deferred in Account 182.3 at
Beginning of Year
(e)
Department
(f)
Account No.
(g)
1 Federal Energy Regulatory Commission:
2 Statutory fees assessed by FERC 4,730,738 4,730,738 Electric 928
3 General regulatory matters 153,408 153,408 Electric 928
4 Oregon Hydro Fees 158,501 158,501 Electric 928
5 Regulatory Commission Expenses - Idaho:
6 General regulatory matters 16,006 Electric 928
7 Regulatory Commission Expenses - Oregon:
8 Statutory fees assessed by Commission 24,440 Electric 928
9 General regulatory matters 1,592,697 1,592,697 Elecrtic 928
46 TOTAL 4,889,239 1,746,105 6,635,344 40,446
FERC FORM NO. 1 (ED. 12-96)
Page 350-351
REGULATORY COMMISSION EXPENSES
EXPENSES INCURRED DURING YEAR EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR AMORTIZED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Line
No.
Amount
(h)
Deferred to Account 182.3
(i)
Contra Account
(j)
Amount
(k)
Deferred in Account 182.3 End of Year
(l)
1
2 4,730,738
3 153,408
4 158,501
5
6 16,750 928203, 419000 25,544 7,212
7
8 31,817 928303, 419000 14,348 41,909
9 1,592,697
46 6,635,344 48,567 39,892 49,121
FERC FORM NO. 1 (ED. 12-96)
Page 350-351
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Line
No.
Classification
(a)
Description
(b)
Costs Incurred Internally Current Year
(c)
Costs Incurred Externally Current Year
(d)
1 Idaho Power did not incur any research and development expenditures in
2021.
FERC FORM NO. 1 (ED. 12-87)
Page 352-353
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
AMOUNTS CHARGED IN CURRENT YEAR AMOUNTS CHARGED IN CURRENT YEAR
Line No.Amounts Charged In Current Year: Account
(e)
Amounts Charged In Current Year: Amount
(f)
Unamortized Accumulation
(g)
1
FERC FORM NO. 1 (ED. 12-87)
Page 352-353
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
DISTRIBUTION OF SALARIES AND WAGES
Line
No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for Clearing
Accounts
(c)
Total
(d)
1 Electric
2 Operation
3 Production 21,617,796
4 Transmission 7,035,828
5 Regional Market
6 Distribution 18,091,441
7 Customer Accounts 9,156,914
8 Customer Service and Informational 4,680,357
9 Sales
10 Administrative and General 76,231,216
11 TOTAL Operation (Enter Total of lines 3 thru 10)136,813,552
12 Maintenance
13 Production 5,182,180
14 Transmission 3,401,760
15 Regional Market
16 Distribution 7,422,124
17 Administrative and General 910,661
18 TOTAL Maintenance (Total of lines 13 thru 17)16,916,725
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)26,799,976
21 Transmission (Enter Total of lines 4 and 14)10,437,588
22 Regional Market (Enter Total of Lines 5 and 15)0
23 Distribution (Enter Total of lines 6 and 16)25,513,565
24 Customer Accounts (Transcribe from line 7)9,156,914
25 Customer Service and Informational (Transcribe from line 8)4,680,357
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)77,141,877
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)153,730,277 153,730,277
29 Gas
30 Operation
31 Production - Manufactured Gas
32 Production-Nat. Gas (Including Expl. And Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)0
42 Maintenance
43 Production - Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)0
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)0
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,0
54 Other Gas Supply (Enter Total of lines 33 and 45)0
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru 0
56 Transmission (Lines 35 and 47)0
57 Distribution (Lines 36 and 48)0
58 Customer Accounts (Line 37)
59 Customer Service and Informational (Line 38)
FERC FORM NO. 1 (ED. 12-88)
Page 354-355
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)0
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)0 0
63 Other Utility Departments
64 Operation and Maintenance 0
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64)153,730,277 0 153,730,277
66 Utility Plant
67 Construction (By Utility Departments)
68 Electric Plant 0
69 Gas Plant 0
70 Other (provide details in footnote):0
71 TOTAL Construction (Total of lines 68 thru 70)0 0 0
72 Plant Removal (By Utility Departments)
73 Electric Plant 0
74 Gas Plant 0
75 Other (provide details in footnote):0
76 TOTAL Plant Removal (Total of lines 73 thru 75)0 0 0
77 Other Accounts (Specify, provide details in footnote):
78 Store Expense 5,265,240 5,265,240
79 Other Clearing Accounts 3,798,193 3,798,193
80 Construction Work in Progress 70,643,100 70,643,100
81 Other Work in Progress 4,199,296 4,199,296
82 Other Accounts 5,067,725 5,067,725
83 Indirect Loading (a)53,537,083 53,537,083
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 88,973,554 53,537,083 142,510,637
96 TOTAL SALARIES AND WAGES 242,703,831 53,537,083 296,240,914
FERC FORM NO. 1 (ED. 12-88)
Page 354-355
DISTRIBUTION OF SALARIES AND WAGES
Line
No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for Clearing
Accounts
(c)
Total
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: SalariesAndWagesOtherAccounts
Page 354 Line 83: Amount reported is total amount of indirect loading. The loading is allocated to departments based on labor charges.
FERC FORM NO. 1 (ED. 12-88)
Page 354-355
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Amount Purchased for the Year Amount Purchased for the Year Amount Purchased for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant Usage - Related Billing Determinant
Line
No.
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of Measure
(c)
Dollar
(d)
1 Scheduling, System Control and Dispatch (a)350,649
2 Reactive Supply and Voltage 115,453
3 Regulation and Frequency Response
4 Energy Imbalance
5 Operating Reserve - Spinning 3,603
6 Operating Reserve - Supplement 3,105
7 Other
8 Total (Lines 1 thru 7)0 472,810
FERC FORM NO. 1 (New 2-04)
Page 398
PURCHASES AND SALES OF ANCILLARY SERVICES
Amount Sold for the Year Amount Sold for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant Usage - Related Billing Determinant
Line No.Number of Units
(e)
Unit of Measure
(f)
Dollars
(g)
1
2
3 3,771,326 KW 369,401
4
5 4,651,367 KW 455,601
6 4,651,367 KW 455,601
7
8 13,074,060 1,280,603
FERC FORM NO. 1 (New 2-04)
Page 398
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: AncillaryServicesPurchasedNumberOfUnits
Idaho Power does not systematically record the number of units related to ancillary services purchased.
FERC FORM NO. 1 (New 2-04)
Page 398
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Line
No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Firm Network Service for Self
(e)
Firm Network Service for
Others
(f)
Long-Term
Firm Point-
to-point
Reservations
(g)
Other
Long-
Term
Firm
Service
(h)
Short-Term
Firm Point-
to-point
Reservation
(i)
Other
Service
(j)
NAME OF SYSTEM: IDAHO POWER COMPANY
- SYSTEM LOAD
1 January 3,380 20 9 1,746 242 975 0 417 0
2 February 3,370 18 8 1,896 244 975 0 255 0
3 March 3,251 1 8 1,726 234 975 0 316 0
4 Total for Quarter 1 5,368 720 2,925 0 988 0
5 April 3,556 30 19 2,045 272 1,175 0 64 0
6 May 4,009 17 19 2,220 314 1,175 0 300 0
7 June 5,283 30 20 3,193 389 1,175 0 526 0
8 Total for Quarter 2 7,458 975 3,525 0 890 0
9 July 4,802 29 16 2,863 374 1,175 0 390 0
10 August 4,744 13 18 2,062 374 1,175 0 1,133 0
11 September 4,272 9 18 2,613 310 1,175 0 174 0
12 Total for Quarter 3 7,538 1,058 3,525 0 1,697 0
13 October 3,064 25 20 1,328 170 1,177 0 389 0
14 November 3,299 8 8 1,808 195 1,177 0 119 0
15 December 3,681 28 19 1,809 244 1,177 0 451 0
16 Total for Quarter 4 4,945 609 3,531 0 959 0
17 Total 25,309 3,362 13,506 0 4,534 0
NAME OF SYSTEM: Idaho Power Company
1 January 3,380 20 9 1,746 242 975 0 417 0
2 February 3,370 18 8 1,896 244 975 0 255 0
3 March 3,251 1 8 1,726 234 975 0 316 0
4 Total for Quarter 1 5,368 720 2,925 0 988 0
5 April 3,556 30 19 2,045 272 1,175 0 64 0
6 May 4,009 17 19 2,220 314 1,175 0 300 0
7 June 5,283 30 20 3,193 389 1,175 0 526 0
8 Total for Quarter 2 7,458 975 3,525 0 890 0
9 July 4,802 29 16 2,863 374 1,175 0 390 0
10 August 4,744 13 18 2,062 374 1,175 0 1,133 0
11 September 4,272 9 18 2,613 310 1,175 0 174 0
12 Total for Quarter 3 7,538 1,058 3,525 0 1,697 0
13 October 3,064 25 20 1,328 170 1,177 0 389 0
14 November 3,299 8 8 1,808 195 1,177 0 119 0
15 December 3,681 28 19 1,809 244 1,177 0 451 0
16 Total for Quarter 4 4,945 609 3,531 0 959 0
17 Total
FERC FORM NO. 1 (NEW. 07-04)
Page 400
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2022-04-15
Year/Period of Report
End of: 2021/ Q4
ELECTRIC ENERGY ACCOUNT
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including Interdepartmental Sales)15,405,799
3 Steam 2,980,808 23 Requirements Sales for Resale (See instruction 4, page 311.)
4 Nuclear 24 Non-Requirements Sales for Resale (See instruction 4, page 311.)1,339,089
5 Hydro-Conventional 5,381,734 25 Energy Furnished Without Charge
6 Hydro-Pumped Storage 26 Energy Used by the Company (Electric Dept Only, Excluding Station Use)(a)
7 Other 2,765,791 27 Total Energy Losses 1,076,855
8 Less Energy for Pumping 27.1 Total Energy Stored
9 Net Generation (Enter Total of lines 3 through 8)11,128,333 28 TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20
UNDER SOURCES 17,821,743
10 Purchases (other than for Energy Storage)6,829,255
10.1 Purchases for Energy Storage 0
11 Power Exchanges:
12 Received 38,171
13 Delivered 166,992
14 Net Exchanges (Line 12 minus line 13)(128,821)
15 Transmission For Other (Wheeling)
16 Received 9,081,201
17 Delivered 9,088,225
18 Net Transmission for Other (Line 16 minus line 17)(b)(7,024)
19 Transmission By Others Losses
20 TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)17,821,743
FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2022-04-15
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: InternalUseEnergy
Page 401a Line 26: Included in energy losses
(b) Concept: NetTransmissionEnergyForOthersElectricPowerWheeling
Page 401a Line 18:
Page 329 Column I differs from page 401 by 7,024 MWH,reported for Wheeling variation and BPA Energy imbalance schedules on page 401.The numbers that are shown on pages 328-330 are for account 456 wheeling only,the numbers on page 401 have to be adjusted for account 447
transmission.
FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
MONTHLY PEAKS AND OUTPUT
Line
No.
Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirement Sales for
Resale & Associated Losses
(c)
Monthly Peak - Megawatts
(d)
Monthly Peak - Day of Month
(e)
Monthly Peak - Hour
(f)
NAME OF SYSTEM: IDAHO POWER COMPANY - SYSTEM
LOAD
29 January 1,435,989 128,732 2,164 20 9
30 February 1,281,421 111,923 2,152 18 8
31 March 1,246,148 91,318 2,043 1 8
32 April 1,170,477 15,742 2,131 30 19
33 May 1,398,244 57,607 2,524 17 19
34 June 1,845,093 27,397 3,751 30 19
35 July 2,062,978 73,898 3,701 6 17
36 August 1,708,342 84,212 3,242 4 18
37 September 1,511,074 236,150 2,795 9 19
38 October 1,309,722 184,121 1,895 4 18
39 November 1,292,327 134,193 2,044 23 10
40 December 1,559,929 193,796 2,265 28 19
41 Total
FERC FORM NO. 1 (ED. 12-90)
Page 401b
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
Steam Electric Generating Plant Statistics
1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service.
Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional
steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c)
any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.
Line
No.
Item
(a)
Plant Name:
Bennett Mountain
Plant Name:
Boardman
Plant Name:
Danskin
Plant Name:
Jim Bridger
Plant Name:
Langley Gulch
Plant
Name:
Valmy
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear)Gas Turbine STEAM Gas Turbine STEAM Gas Turbine STEAM
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional Conventional Conventional SEMI-OUTDOOR BOILER Conventional Outdoor
3 Year Originally Constructed 2005 (a)
1980 2001 (b)
1974 2012 (c)
1981
4 Year Last Unit was Installed 2005 1980 2008 1979 2012 1985
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)172.8 (d)0 270.9 (e)775.21 318.45 (f)144.9
6 Net Peak Demand on Plant - MW (60 minutes)176 0 266 710 298 252
7 Plant Hours Connected to Load 2,693 0 3,175 8,760 7,543 4,775
8 Net Continuous Plant Capability (Megawatts)199 252 329
9 When Not Limited by Condenser Water 0 (g)0 0 (h)0 0 (i)0
10 When Limited by Condenser Water 0 0 0 0 0 0
11 Average Number of Employees 4 0 6 0 24 0
12 Net Generation, Exclusive of Plant Use - kWh 354,344,000 0 484,314,000 2,564,270,000 1,927,107,000 416,538,000
13 Cost of Plant: Land and Land Rights 0 106,610 402,745 509,671 2,287,261 1,106,140
14 Structures and Improvements 1,878,039 0 6,067,099 73,435,939 146,628,907 47,509,962
15 Equipment Costs 53,746,809 0 105,159,813 659,664,903 237,665,762 202,358,533
16 Asset Retirement Costs 0 3,767,793 0 22,964,034 0 (191,622)
17 Total cost (total 13 thru 20)55,624,848 3,874,403 111,629,657 756,574,547 386,581,930 250,783,013
18 Cost per KW of Installed Capacity (line 17/5) Including 321.9031 412.0696 975.9608 1,213.9486 1,730.7316
19 Production Expenses: Oper, Supv, & Engr 4,920 27,489 48,205 216,533 537,788 656,960
20 Fuel 13,084,165 23,712 19,437,603 78,513,873 52,698,638 16,786,248
21 Coolants and Water (Nuclear Plants Only)0 0 0 0 0 0
22 Steam Expenses 0 0 0 5,568,669 0 3,662,387
23 Steam From Other Sources 0 0 0 0 0 0
24 Steam Transferred (Cr)0 0 0 0 0 0
25 Electric Expenses 327,596 0 907,910 0 3,536,915 1,282,126
26 Misc Steam (or Nuclear) Power Expenses 140,531 40 167,055 7,371,196 1,113,706 1,114,170
27 Rents 0 0 0 216,916 0 0
28 Allowances 0 0 0 0 0 0
29 Maintenance Supervision and Engineering 0 (46,976)0 45,222 0 0
30 Maintenance of Structures 45,678 0 52,175 0 66,106 1,278,996
31 Maintenance of Boiler (or reactor) Plant 17,372 0 7,091 6,133,397 38,972 2,777,041
32 Maintenance of Electric Plant 257,904 0 414,534 2,218,897 1,508,622 473,434
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0 0 7,910,938 0 145,811
34 Total Production Expenses 13,878,166 4,265 21,034,573 108,195,641 59,500,747 28,177,173
35 Expenses per Net kWh 0.0392 0.0434 0.0422 0.0309 0.0676
35 Plant Name Bennett Mountain Boardman Boardman Danskin Jim Bridger Jim
Bridger
Langley
Gulch Valmy Valmy
36 Fuel Kind Gas Coal Oil Gas Coal Oil Gas Coal Oil
37 Fuel Unit MCF Tons Barrels MCF Tons Barrels MCF Tons Barrels
38 Quantity (Units) of Fuel Burned 3,788,475 5,186,842 1,449,645 5,722 13,331,938 214,301 4,238
39 Avg Heat Cont - Fuel Burned (btu/indicate if
nuclear)1,027 0 0 1,027 9,548 140,000 1,027 10,764 138,778
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.454 0 0 3.747 57.015 2.295 3.953 35.606 0
41 Average Cost of Fuel per Unit Burned 3.454 0 0 3.747 53.485 138.021 3.953 76.105 104.247
42 Average Cost of Fuel Burned per Million BTU 3.82 0 0 4.16 2.801 23.472 4.41 3.633 17.886
43 Average Cost of Fuel Burned per kWh Net Gen 0.037 0 0 0.04 0.031 0 0.027 0.04 0
44 Average BTU per kWh Net Generation 10,980.188 0 0 10,998.829 10,809 0 7,104.899 10,836 0
FERC FORM NO. 1 (REV. 12-03)
Page 402-403
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: YearPlantOriginallyConstructed
This footnote applies to lines 3 and 4. The Boardman plant consists of one unit constructed jointly by Portland General Electric Company, Idaho Power Company, and Pacific Northwest Generating Company, with Idaho Power owning 10% . The unit was placed in
commercial operation August 3, 1980 and ceased operations in October 2020.
(b) Concept: YearPlantOriginallyConstructed
This footnote applies to lines 3 and 4. The Jim Bridger Power Plant consists of four equal units constructed jointly by Idaho Power Company and Pacific Power and Light Company, with Idaho Power owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975, Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
(c) Concept: YearPlantOriginallyConstructed
This footnote applies to lines 3 and 4. The Valmy plant consists of two units constructed jointly by Sierra Pacific Power Company and Idaho Power Company, with Sierra owning 1/2 and Idaho Power owning 1/2. Unit #1 was placed in commercial operation
December 11, 1981, and Unit #2 May 21, 1985. Idaho Power ended its participation in Unit #1 in December 2019.
(d) Concept: InstalledCapacityOfPlant
This footnote applies to line 5 and line 12 through 43. Information reflects Idaho Power Company's share as explained in the note for line 3 page 402 under Boardman.
(e) Concept: InstalledCapacityOfPlant
This footnote applies to line 5 and line 12 through 43. Information reflects Idaho Power Company's share as explained in the note for line 3 page 402 under Jim Bridger.
(f) Concept: InstalledCapacityOfPlant
This footnote applies to line 5 and line 12 through 43. Information reflects Idaho Power Company's share as explained in the note for line 3 page 402 under Valmy.
(g) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater
This footnote applies to line 9, 10, and 11. Portland General Electric Company , as operator of the plant, will report this information.
(h) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater
This footnote applies to line 9, 10, and 11. PacifiCorp, as operator of the plant, will report this information.
(i) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater
This footnote applies to line 9, 10, and 11. Sierra Pacific Power, as operator of the plant, will report this information.
FERC FORM NO. 1 (REV. 12-03)
Page 402-403
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
Hydroelectric Generating Plant Statistics
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified
as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Line
No.
Item
(a)
FERC
Licensed
Project No.
2736
Plant
Name:
American
Falls
FERC
Licensed
Project No.
1975
Plant
Name:
Bliss
FERC
Licensed
Project No.
1971
Plant Name:
Brownlee
FERC
Licensed
Project No.
2055
Plant
Name:
C J Strike
FERC
Licensed
Project
No.
2848
Plant
Name:
Cascade
FERC
Licensed
Project
No.
1971
Plant
Name:
Common
Facilities
FERC
Licensed
Project No.
1971
Plant Name:
Hells Canyon
FERC
Licensed
Project No.
2061
Plant
Name:
Lower
Salmon
FERC
Licensed
Project No.
2726
Plant
Name:
Malad
FERC
Licensed
Project No.
2899
Plant Name:
Milner
FERC
Licensed
Project No.
1971
Plant
Name:
Oxbow
FERC
Licensed
Project No.
2778
Plant Name:
Shoshone
Falls
FERC
Licensed
Project No.
503
Plant Name:
Swan Falls
FERC
Licensed
Project No.
18
Plant Name:
Twin Falls
FERC
Licensed
Project No.
2777
Plant
Name:
Upper
Salmon
1
Kind of Plant
(Run-of-River
or Storage)
Run-of-
River
Run-of-
River Storage Run-of-
River
Run-of-
River Storage Run-of-
River
Run-of-
River Run-of-River Storage Run-of-River Run-of-River Run-of-River Run-of-
River
2
Plant
Construction
type
(Conventional
or Outdoor)
Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Conventional Outdoor Conventional Conventional Conventional Outdoor
3
Year
Originally
Constructed
1978 1949 1958 1952 1983 1967 1949 1948 1992 1961 1907 1910 1935 1937
4 Year Last Unit
was Installed 1978 1950 1980 1952 1984 1967 1949 1948 1992 1961 1921 1994 1995 1947
5
Total installed
cap (Gen
name plate
Rating in
MW)
92.34 75 675 82.8 12.42 391.5 60 21.77 59.45 190 14.73 27.17 52.9 34.5
6
Net Peak
Demand on
Plant-
Megawatts
(60 minutes)
98 66 634 88 12 284 49 24 58 214 15 21 51 35
7
Plant Hours
Connect to
Load
6,154 8,760 8,760 8,760 8,755 8,760 8,760 8,032 2,332 8,760 8,360 8,712 8,760 8,450
8
Net Plant
Capability (in
megawatts)
9
(a) Under
Most
Favorable
Oper
Conditions
109 76 747 91 15 445 64 25 61 221 14 24 53 36
10
(b) Under the
Most Adverse
Oper
Conditions
0 1 220 84 1 137 60 21 1 202 11 14 50 32
11
Average
Number of
Employees
3 4 6 4 7 35 1 4 4 5 2 37 2 6
12
Net
Generation,
Exclusive of
Plant Use -
kWh
251,488,000 302,895,000 1,543,109,000 363,276,000 26,262,000 1,408,617,000 200,329,000 146,997,000 34,722,000 685,996,000 53,470,000 107,811,000 43,071,000 143,466,000
13 Cost of Plant
14 Land and
Land Rights 875,319 768,366 18,474,575 5,725,987 82,142 114,367 2,113,754 424,428 205,376 138,100 1,212,767 313,328 309,958 255,499 202,399
15
Structures
and
Improvements
12,116,306 1,935,186 41,958,815 10,157,626 7,328,252 65,751,575 6,659,478 3,547,108 15,301,738 10,664,732 19,185,007 7,093,484 27,909,738 12,004,023 3,142,130
16
Reservoirs,
Dams, and
Waterways
4,293,075 11,418,401 71,549,767 12,253,921 3,145,630 13,556,785 55,079,600 8,081,511 7,407,203 17,779,586 31,518,394 15,103,834 16,061,292 9,024,651 17,768,318
17 Equipment
Costs 33,288,285 20,491,336 141,943,606 15,086,264 13,496,853 3,450,420 22,631,958 27,474,777 16,996,735 29,332,473 22,303,753 18,385,701 32,525,751 25,085,022 9,406,821
18
Roads,
Railroads,
and Bridges
839,276 486,477 1,543,782 1,602,868 122,668 142,581 1,357,864 88,693 1,507,442 501,877 2,548,566 468,609 835,946 1,917,603 29,359
19
Asset
Retirement
Costs
20
Total cost
(total 13 thru
20)
51,412,261 35,099,766 275,470,545 44,826,666 24,175,545 83,015,728 87,842,654 39,616,517 41,418,494 58,416,768 76,768,487 41,364,956 77,642,685 48,286,798 30,549,027
21
Cost per KW
of Installed
Capacity (line
20 / 5)
556.7713 467.9969 408.1045 541.3849 1,946.5012 224.3746 660.2753 1,902.5491 982.6202 404.0447 2,808.2115 2,857.6623 912.7939 885.479
22 Production
Expenses
23
Operation
Supervision
and
Engineering
371,376 205,959 795,433 526,975 291,542 0 552,677 346,542 87,447 172,051 706,127 101,528 333,027 587,406 240,681
24 Water for
Power 2,439,122 345,408 275,165 160,744 136,043 0 216,171 127,362 693,696 602,990 215,191 42,896 136,230 137,918 104,718
25 Hydraulic
Expenses 377,262 268,451 751,193 444,286 320,939 10,621,878 608,294 400,959 89,144 173,819 619,519 122,516 429,398 396,803 319,544
26 Electric
Expenses 90,021 76,398 268,741 48,142 130,753 0 294,441 150,811 22,281 44,330 198,350 45,855 175,707 54,563 133,956
27
Misc
Hydraulic
Power
Generation
Expenses
453,849 210,696 706,341 345,717 317,269 0 653,308 277,632 98,667 220,314 636,402 113,754 304,730 246,648 214,683
28 Rents 355 8,422 129,000 74,616 83 0 35,181 6,745 0 6,432 21,151 369 16,697 7,511 0
29
Maintenance
Supervision
and
Engineering
10,890 9,591 16,467 12,347 5,010 0 9,308 8,304 4,715 5,503 11,067 5,509 13,379 4,460 11,940
30 Maintenance
of Structures 85,983 80,222 66,235 153,979 19,765 0 25,572 107,804 19,702 45,173 42,087 72,286 122,967 40,874 65,434
31
Maintenance
of Reservoirs,
Dams, and
Waterways
42,480 40,351 17,467 99,416 1,888 0 2,968 50,782 66,080 45,181 2,772 19,697 64,221 21,338 80,996
32
Maintenance
of Electric
Plant
213,014 176,842 301,515 242,431 81,457 0 120,856 188,024 71,740 108,193 151,377 122,903 318,242 107,779 291,684
33
Maintenance
of Misc
Hydraulic
Plant
239,967 214,672 447,142 163,384 150,141 189,528 321,101 96,722 76,583 95,272 386,120 79,251 208,869 68,135 199,344
34
Total
Production
Expenses
(total 23 thru
33)
4,324,319 1,637,012 3,774,699 2,272,037 1,454,890 10,811,406 2,839,877 1,761,687 1,230,055 1,519,258 2,990,163 726,564 2,123,467 1,673,435 1,662,980
35 Expenses per
net kWh 0.0172 0.0054 0.0024 0.0063 0.0554 0.002 0.0088 0.0084 0.0438 0.0044 0.0136 0.0197 0.0389 0.0116
FERC FORM NO. 1 (REV. 12-03)
Page 406-407
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
GENERATING PLANT STATISTICS (Small Plants)
Line
No.
Name of Plant
(a)
Year Orig. Const.
(b)
Installed Capacity Name Plate
Rating (MW)
(c)
Net Peak Demand MW (60 min)
(d)
Net Generation Excluding Plant Use
(e)
Cost of Plant
(f)
1 Hydro
2 Clear Lakes 1937 2.5 2.3 17,030 3,595,811
3 Thousand Springs 1912 6.8 8.8 53,195 11,724,750
4 Internal Combustion
5 Salmon Diesel 1967 5 2.8 26 884,134
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
GENERATING PLANT STATISTICS (Small Plants)
Production Expenses Production Expenses
Line
No.
Plant Cost (Incl Asset Retire. Costs)
Per MW
(g)
Operation Exc'l. Fuel
(h)
Fuel Production Expenses
(i)
Maintenance Production Expenses
(j)
Kind of Fuel
(k)
Fuel Costs (in cents (per Million
Btu)
(l)
1
2 1,438,324 62,295 24,931
3 1,724,228 394,027 330,873
4
5 176,827 Diesel
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
GENERATING PLANT STATISTICS (Small Plants)
Line No.Generation Type
(m)
1
2
3
4
5
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
1 Borah (a)
Midpoint 345 500 S Tower 62.35 0 1
2 Boardman
(b)
Slatt 500 500 S Tower 1.79 0 1
3 Summer lake (c)
Hemingway 500 500 S Tower 0.08 0 1
4 Hemingway (d)
Midpoint 500 500 S Tower 0.15 0 1
5 Summer Lake (e)
Hemingway 500 500 S Tower 53.07 0 1
6 Hemingway (f)
Midpoint 500 500 S Tower 47.76 0 1
7 Jim Bridger (g)
Goshen 345 345 S Tower 66.15 0 1
8 State Line Midpoint 345 345 S Tower 76.06 0 2
9 Kinport (h)
Borah 345 345 S Tower 19.81 0 1
10 Jim Bridger (i)
Populus 345 345 S Tower 60.93 0 1
11 Populus (j)
Kinport 345 345 S Tower 7.42 0 1
12 Jim Bridger (k)
Populus 345 345 S Tower 61.1 0 1
13 Populus (l)
Borah 345 345 S Tower 9.05 0 1
14 Goshen (m)
Kinport 345 345 S Tower 7.49 0 1
15 Midpoint (n)
Borah #1 345 345 H Wood 51.07 0 1
16 Midpoint (o)
Borah #2 345 345 H Wood 49.98 0 2
17 Adelaide Tap (p)
Adelaide 345 345 H Wood 1.72 0 2
18 Quartz LaGrande 230 230 H Wood 45.97 0 1
19 Midpoint Hunt 230 230 S Tower 0.7 0 2
20 Brady Antelope 230 230 H Wood 56.38 0 1
21 Brady Treasureton 230 230 H Wood 0.08 0 1
22 Brady #1 & #2 Kinport 230 230 S Tower 17.94 0 2
23 Brownlee Ontario 230 230 S Tower 72.67 0 1
24 Mora Bowmont 138 230 S P Wood 9.99 0 1
25 Mora Bowmont 138 230 H Wood 8.75 0 1
26 Caldwell 710 Locust 230 230 SP Steel 18.5 0 1
27 Boise Bench Caldwell 230 230 S Tower 7.69 0 1
28 Boise Bench Caldwell 230 230 H Wood 33.49 0 1
29 Boise Bench Cloverdale 230 230 S Tower 16.08 0 2
30 Boardman (q)
Dalreed Sub 230 230 H Wood 1.67 0 1
31 Brownlee 714 Oxbow 230 230 SP Steel 10.96 0 2
32 Caldwell Ontario 230 230 H Wood 30.06 0 1
33 Caldwell Ontario 230 230 S Tower 3.14 0 1
34 Bennett Mtn PP Rattlesnake TS 230 230 SP Steel 4.39 0 1
35 Borah Hunt 230 230 H Steel 68.12 0 1
36 Danskin Hubbard 230 230 H Steel 36.25 0 1
37 Danskin Hubbard 230 230 SP Steel 1.84 0 1
38 Danskin Hubbard 230 230 SP Steel 1.3 0 2
39 Danskin Bennett Mtn 230 230 SP Steel 5.39 0 1
40 Hemingway Bowmont 230 230 SP Steel 12.94 0 1
41 Langley Gulch Galloway Rd 138 230 SP Steel 14.19 0 1
42 Galloway Rd Willis Tap 138 230 SP Steel 2.09 0 1
43 Walla Walla (r)
Hurricane 230 230 H Wood 31.67 0 1
44 Cloverdale Hubbard 230 230 SP Steel 6.87 0 2
45 Boise Bench Midpoint #1 230 230 S Tower 0.71 0 1
46 Boise Bench Midpoint #1 230 230 H Wood 108.67 0 1
47 Brownlee Quartz Jct 230 230 S Tower 1.51 0 1
48 Brownlee Quartz Jct 230 230 H Wood 41.3 0 1
49 Brownlee Boise Bench #1 & #2 230 230 S Tower 99.78 0 2
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
50 Oxbow Brownlee 230 230 S Tower 10.32 0 2
51 Boise Bench Midpoint #2 230 230 S Tower 3.49 0 1
52 Boise Bench Midpoint #2 230 230 H Wood 102.17 0 1
53 Oxbow Pallette Jct 230 230 S Tower 19.97 0 2
54 Pallette Jct Imnaha 230 230 H Wood 24.43 0 2
55 Hells Canyon Palette Jct 230 230 S Tower 9.05 0 2
56 Brownlee Boise Bench 230 230 S Tower 102.1 0 2
57 Boise Bench Midpoint #3 230 230 H Wood 106.29 0 1
58 Palette Jct Enterprise 230 230 H Wood 29.6 0 1
59 Borah Brady #2 230 230 S Tower 0.42 0 1
60 Borah Brady #2 230 230 H Wood 3.52 0 1
61 Borah Brady #1 230 230 H Wood 3.84 0 1
62 Goshen (s)
State Line 161 161 H Wood 40.89 0 1
63 Don Goshen 161 161 S Tower 2.37 0 2
64 Don Goshen 161 161 H Wood 16.49 0 2
65 Don Goshen 138 161 H Wood 29.64 0 2
66 Antelope (t)
Goshen 161 161 H Wood 5.68 0 1
67 Goshen (u)
State Line 161 161 H Wood 10.9 0 1
68 Goshen (v)
State Line 161 161 H Wood 7.84 0 1
69 American Falls Power Plant Adelaide 138 138 H Wood 14.07 0 2
70 American Falls Power Plant Adelaide 138 138 S P Wood 0.12 0 2
71 Minidoka Loop Adelaide 138 138 S Tower 1.13 0 2
72 Nampa Caldwell 138 138 S P Wood 9.59 0 2
73 Skyway Tap 138 138 S P Steel 0.89 0 2
74 Upper Salmon Mountain Home Jct 138 138 H Wood 54.36 0 1
75 Upper Salmon Cliff 138 138 H Wood 30.81 0 1
76 Eastgate Russet 138 138 S P Wood 2.06 0 1
77 Brady Fremont 138 138 S Tower 1.01 0 2
78 Brady Fremont 138 138 H Wood 24.36 0 2
79 Brady Fremont 138 138 S P Wood 24.33 0 2
80 King Lower Malad 138 138 H Wood 84.71 0 2
81 Emmett Jct Payette 138 138 H Wood 66.46 0 2
82 Mountain Home AFB Tap 138 138 H Wood 6.2 0 1
83 Ontario Quartz 138 138 H Wood 73.2 0 1
84 King American Falls PP 138 138 S Tower 0.91 0 2
85 King American Falls PP 138 138 H Wood 142.05 0 1
86 King American Falls PP 138 138 S P Wood 3.71 0 1
87 Duffin Clawson 138 138 H Wood 6.19 0 1
88 American Falls Brady Tie 138 138 H Wood 0.33 0 1
89 Upper Salmon A-B King 138 138 H Wood 5.66 0 1
90 Upper Salmon B Wells 138 138 H Wood 125.47 0 1
91 King Wood River 138 138 H Wood 73.72 0 1
92 Toponis Pocket 138 138 S P Wood 9.8 0 1
93 Boise Bench Grove 138 138 S P Wood 10.37 0 2
94 Quartz John Day 138 138 H Wood 67.3 0 1
95 Sinker Creek Tap 138 138 H Wood 2.79 0 1
96 Mora Cloverdale 138 138 H Wood 2.51 0 1
97 Mora Cloverdale 138 138 S P Wood 22.27 0 1
98 Mora Cloverdale 138 138 S P Steel 0.96 0 2
99 Stoddard Jct Stoddard Sub 138 138 S P Steel 3.8 0 1
100 Fossil Gulch Tap 138 138 H Wood 1.81 0 1
101 Wood River Midpoint 138 138 H Wood 53.08 0 2
102 Wood River Midpoint 138 138 S P Wood 16.69 0 2
103 Oxbow McCall 138 138 H Wood 37.04 0 1
104 Oxbow McCall 138 138 S P Wood 2.32 0 1
105 Lowell Jct Nampa 138 138 S P Wood 7.49 0 2
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
106 Hunt Milner 138 138 S P Wood 19.41 0 1
107 Strike Bruneau Bridge 138 138 H Wood 13.49 0 1
108 American Falls Kramer Sub 138 138 S P Wood 18.46 0 2
109 Pingree Haven 138 138 S P Wood 11.72 0 1
110 Midpoint Twin Falls 138 138 S P Wood 25.2 0 2
111 Shoshone Tap 138 138 H Wood 7.09 0 2
112 Twin Falls Russett 138 138 S P Wood 1.71 0 1
113 Blackfoot Aiken 46 138 S P Wood 6.22 0 2
114 Peterson Tendoy 69 138 H Wood 57.03 0 1
115 Eastgate Tap Eastgate 138 138 S P Wood 6.36 0 1
116 Kimberly Tap Kimberly 138 138 S P Steel 1.84 0 2
117 Boise Bench Mora 138 138 H Wood 13.1 0 2
118 Bowmont-Caldwell Simplot Sub 138 138 S P Wood 0.51 0 1
119 Gary Lane Eagle 138 138 S P Wood 6.65 0 1
120 Locust Grove Blackcat Sub 138 138 S P Steel 9.26 2.98 1
121 Boise Bench Butler 138 138 S P Wood 0.14 4.02 1
122 Eagle Star 138 138 S P Wood 6.75 0 1
123 Star Lansing 138 138 S P Steel 5.5 0 1
124 Beacon Light Tap Beacon Light 138 138 S P Steel 4.32 0 1
125 Karcher Sub Zilog Tap 138 138 S P Steel 3.12 0 1
126 Zilog Can Ada 138 138 S P Steel 1.5 0 1
127 Blackcat Can Ada 138 138 H Wood 3.42 0 1
128 Cloverdale - 712 712 - Wye 138 138 S P Steel 0.42 4.02 1
129 Victory Jct Victory 138 138 S P Steel 1.89 0 1
130 Butler Wye 138 138 S P Steel 2.94 0 1
131 Horseflat Starkey 138 138 H Wood 33.97 0 1
132 Starkey Mccall 138 138 S P Steel 2.23 0 2
133 Starkey Mccall 138 138 H Wood 3.8 0 1
134 Starkey Mccall 138 138 S P Steel 1.5 0 1
135 Starkey Mccall 138 138 S P Wood 17.61 0 1
136 Chestnut Happy Valley 138 138 S P Steel 2.78 0 1
137 Garnet Ward 0 138 0 0 0
138 McCall Lake Fork 138 138 S P Wood 8.89 0 1
139 McCall Lake Fork 138 138 S Steel 2.9 0 1
140 Boulder Tap 138 138 S P Steel 1.98 0 1
141 Caldwell Willis 138 138 S P Steel 1.3 0 1
142 Caldwell Willis 138 138 S P Steel 3.62 0 1
143 Caldwell Willis 138 138 S P Wood 0.87 0 1
144 Willis Lansing 138 138 Verious 3.23 0 2
145 Valivue Tap 138 138 S P Steel 0.79 0 2
146 Bowmont Happy Valley 138 138 S P Steel 8.65 0 1
147 Antelope (w)
Scoville 138 138 H Wood 0.12 0 1
148 American Falls
(x)
Wheelon 138 138 H Wood 1.05 0 1
149 Kinport Don #1 138 138 S Tower 1.27 0 2
150 Donn HOKU 138 138 S P Steel 2.69 0 1
151 HOKU Alamed 138 138 S P Steel 0.22 0 2
152 HOKU Alamed 138 138 S P Steel 0.23 0 2
153 HOKU Alamed 138 138 S P Steel 2.85 0 1
154 Eldridge tap 138 138 S P Steel 0.85 0 1
155 Rockland Jct Rockland Wind Farm 138 138 S P Steel 5.18 0 1
156 King Justice 138 138 S P Wood 0.07 0 1
157 NorthView Tap 138 138 S P Wood 6.17 0 1
158 Twin Falls PP Tap 138 138 H Wood 0.99 0 1
159 American Falls PP Amercian Falls Trans ST 138 138 S P Steel 0.37 0 1
160 Lower Salmon King Tie 138 138 H Wood 0.11 0 1
161 C J Strike Strike Jct 138 138 S Tower 4.3 0 2
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
162 Strike Jct Mountain Home Jct 138 138 H Wood 23.42 0 1
163 Strike Jct Bowmont 0 138 H Wood 0.05 0 1
164 Strike Jct Bowmont 138 138 S Tower 0.36 0 1
165 Strike Jct Bowmont 138 138 H Wood 67.89 0 1
166 Lucky Peak Lucky Peak Jct 138 138 H Wood 4.48 0 2
167 Bliss King 138 138 H Wood 10.51 0 1
168 Milner Deadend Milner PP 138 138 S P Wood 1.3 0 1
169 Swan Falls Tap 138 138 H Wood 0.95 0 1
170 Hines BPA (Harney)115 115 H Wood 3.35 0 1
171 69 Kv Lines 69 69 H Wood 205.81 0 1
172 69 Kv Lines 69 69 S P Wood 876.87 0 1
173 46 Kv Lines 46 46 S P Wood 376.46 0 1
174 Operation, Maintenance, Rents
36 TOTAL 4,785.74 11.02 220
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
TRANSMISSION LINE STATISTICS
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
EXPENSES, EXCEPT
DEPRECIATION AND TAXES
EXPENSES, EXCEPT
DEPRECIATION AND
TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
Line
No.Size of Conductor and Material Land Construction Costs Total Costs Operation Expenses Maintenance Expenses Rents Total Expenses
(i)(j)(k)(l)(m)(n)(o)(p)
1 1272 ACSR 256,381 16,047,911 16,304,292 0 0 0 0
2 2X1780 ACSR 0 446,708 446,708 0 0 0 0
3 1272 ACSR 0 0 0 0 0 0 0
4 1272 ACSR 0 0 0 0 0 0 0
5 3x1272 ACSR 0 18,849,330 18,849,330 0 0 0 0
6 3x1272 ACSR 0 17,078,092 17,078,092 0 0 0 0
7 1272 ACSR 483,309 5,326,681 5,809,990 0 0 0 0
8 795 ACSR 572,297 11,360,835 11,933,132 0 0 0 0
9 1272 ACSR 344,220 4,397,073 4,741,293 0 0 0 0
10 1272 ACSR 0 9,537,131 9,537,131 0 0 0 0
11 1272 ACSR 0 0 0 0 0 0 0
12 1272 ACSR 0 9,259,422 9,259,422 0 0 0 0
13 1272 ACSR 0 0 0 0 0 0 0
14 2x1272 ACSR 0 586,144 586,144 0 0 0 0
15 715.5 ACSR 283,143 20,494,975 20,778,118 0 0 0 0
16 715.5 ACSR 64,851 15,029,349 15,094,200 0 0 0 0
17 715.5 ACSR 51,448 227,554 279,002 0 0 0 0
18 795 ACSR 62,218 7,266,756 7,328,974 0 0 0 0
19 715.5 ACSR 9,145 999,238 1,008,383 0 0 0 0
20 1272 ACSR 163,320 4,711,479 4,874,799 0 0 0 0
21 795 ACSR 0 6,186 6,186 0 0 0 0
22 715.5 ACSR 18,829 1,144,918 1,163,747 0 0 0 0
23 2X954 ACSR 1,676,838 20,730,375 22,407,213 0 0 0 0
24 715.5 ACSR 413,793 2,397,628 2,811,421 0 0 0 0
25 715.5 ACSR 0 0 0 0 0 0 0
26 1590 ACSR 2,378,436 8,775,086 11,153,522 0 0 0 0
27 1272 ACSR 1,748,202 8,551,049 10,299,251 0 0 0 0
28 715.5 ACSR 0 0 0 0 0 0 0
29 1272 ACSR 3,062,812 7,238,489 10,301,301 0 0 0 0
30 795 AAC 0 89,089 89,089 0 0 0 0
31 954 ACSR 34,174 16,026,470 16,060,644 0 0 0 0
32 2X954 ACSR 236,152 9,384,090 9,620,242 0 0 0 0
33 1272 ACSR 0 0 0 0 0 0 0
34 1272 ACSR 81,701 1,666,354 1,748,055 0 0 0 0
35 1590 ACSR 624,917 22,467,321 23,092,238 0 0 0 0
36 1590 ACSR 0 15,210,561 15,210,561 0 0 0 0
37 1590 ACSR 0 0 0 0 0 0 0
38 1590 ACSR 0 0 0 0 0 0 0
39 1590 ACSR 0 3,528,033 3,528,033 0 0 0 0
40 1590 ACSR 1,854,996 9,277,980 11,132,976 0 0 0 0
41 1590 ACSR 948,166 9,067,609 10,015,775 0 0 0 0
42 1272 ACSR 0 0 0 0 0 0 0
43 1272 ACSR 0 6,991,109 6,991,109 0 0 0 0
44 1272 ACSR 293,139 9,170,869 9,464,008 0 0 0 0
45 715.5 ACSR 385,287 14,953,960 15,339,247 0 0 0 0
46 715.5 ACSR 0 0 0 0 0 0 0
47 795 ACSR 53,068 4,881,976 4,935,044 0 0 0 0
48 795 ACSR 0 0 0 0 0 0 0
49 VARIOUS 289,923 9,785,015 10,074,938 0 0 0 0
50 1272 ACSR 14,810 1,489,716 1,504,526 0 0 0 0
51 715.5 ACSR 227,814 18,846,936 19,074,750 0 0 0 0
52 VARIOUS 0 0 0 0 0 0 0
53 1272 ACSR 87,468 3,961,014 4,048,482 0 0 0 0
54 1272 ACSR 171,081 4,251,854 4,422,935 0 0 0 0
55 1272 ACSR 44,687 1,492,660 1,537,347 0 0 0 0
56 954 ACSR 184,805 6,484,895 6,669,700 0 0 0 0
57 715.5 ACSR 247,846 8,192,995 8,440,841 0 0 0 0
58 1272 ACSR 84,014 2,336,189 2,420,203 0 0 0 0
59 1272 ACSR 3,068 864,609 867,677 0 0 0 0
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
60 715.5 ACSR 0 0 0 0 0 0 0
61 1272 ACSR 7,248 514,141 521,389 0 0 0 0
62 250 COPPER 375,576 3,295,662 3,671,238 0 0 0 0
63 715.5 ACSR 88,204 2,516,757 2,604,961 0 0 0 0
64 397.5 ACSR 0 0 0 0 0 0 0
65 397.5 ACSR 0 0 0 0 0 0 0
66 397.5 ACSR 0 797,970 797,970 0 0 0 0
67 250 COPPER 116,873 1,265,124 1,381,997 0 0 0 0
68 250 COPPER 76,969 644,306 721,275 0 0 0 0
69 250 COPPER 26,507 406,847 433,354 0 0 0 0
70 250 COPPER 0 0 0 0 0 0 0
71 715.5 ACSR 21,327 250,486 271,813 0 0 0 0
72 795 AAC 1,798,312 6,016,520 7,814,832 0 0 0 0
73 1272 ACSR 0 0 0 0 0 0 0
74 795 ACSR 78,078 5,041,254 5,119,332 0 0 0 0
75 795 ACSR 43,568 3,459,148 3,502,716 0 0 0 0
76 795 AAC 270,823 561,561 832,384 0 0 0 0
77 VARIOUS 564,932 4,747,848 5,312,780 0 0 0 0
78 VARIOUS 0 0 0 0 0 0 0
79 VARIOUS 0 0 0 0 0 0 0
80 VARIOUS 76,823 4,297,194 4,374,017 0 0 0 0
81 VARIOUS 61,872 4,729,011 4,790,883 0 0 0 0
82 397.5 ACSR 5,086 90,415 95,501 0 0 0 0
83 VARIOUS 127,785 9,009,463 9,137,248 0 0 0 0
84 715.5 ACSR 216,919 12,227,119 12,444,038 0 0 0 0
85 715.5 ACSR 0 0 0 0 0 0 0
86 715.5 ACSR 0 0 0 0 0 0 0
87 4\0 4,191 562,786 566,977 0 0 0 0
88 954 ACSR 0 98,203 98,203 0 0 0 0
89 250 COPPER 2,741 896,947 899,688 0 0 0 0
90 VARIOUS 28,490 4,917,063 4,945,553 0 0 0 0
91 VARIOUS 186,198 24,881,414 25,067,612 0 0 0 0
92 397.5 ACSR 0 0 0 0
93 VARIOUS 225,602 1,646,308 1,871,910 0 0 0 0
94 397.5 ACSR 96,582 3,868,889 3,965,471 0 0 0 0
95 VARIOUS 11,083 137,366 148,449 0 0 0 0
96 715.5 ACSR 3,123,381 11,080,785 14,204,166 0 0 0 0
97 VARIOUS 0 0 0 0 0 0 0
98 795AAC 0 0 0 0 0 0 0
99 1272 ACSR 0 0 0 0 0 0 0
100 250 COPPER 450 190,553 191,003 0 0 0 0
101 397.5 ACSR 349,712 8,424,770 8,774,482 0 0 0 0
102 397.5 ACSR 0 0 0 0 0 0 0
103 397.5 ACSR 141,534 2,760,869 2,902,403 0 0 0 0
104 397.5 ACSR 0 0 0 0 0 0 0
105 715.5 ACSR 211,131 1,465,044 1,676,175 0 0 0 0
106 715.5 ACSR 3,324 1,572,811 1,576,135 0 0 0 0
107 397.5 ACSR 14,927 717,475 732,402 0 0 0 0
108 715.5 ACSR 13,734 1,303,623 1,317,357 0 0 0 0
109 397.5 ACSR 18,223 1,299,173 1,317,396 0 0 0 0
110 VARIOUS 85,826 6,365,867 6,451,693 0 0 0 0
111 397.5 ACSR 0 0 0 0 0 0 0
112 715.5 ACSR 16,790 213,033 229,823 0 0 0 0
113 715.5 ACSR 13,616 580,168 593,784 0 0 0 0
114 397.5 ACSR 395,696 3,617,011 4,012,707 0 0 0 0
115 715.5 ACSR 343,955 2,195,624 2,539,579 0 0 0 0
116 795 ACSR 0 0 0 0 0 0 0
117 715.5 ACSR 14,697 736,552 751,249 0 0 0 0
118 795 AAC 0 50,319 50,319 0 0 0 0
TRANSMISSION LINE STATISTICS
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
EXPENSES, EXCEPT
DEPRECIATION AND TAXES
EXPENSES, EXCEPT
DEPRECIATION AND
TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
Line
No.Size of Conductor and Material Land Construction Costs Total Costs Operation Expenses Maintenance Expenses Rents Total Expenses
(i)(j)(k)(l)(m)(n)(o)(p)
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
119 795 AAC 308,141 2,175,547 2,483,688 0 0 0 0
120 1272 ACSR 935,810 3,852,101 4,787,911 0 0 0 0
121 1272 ACSR 34,687 838,605 873,292 0 0 0 0
122 715.5 ACSR 630,977 8,553,939 9,184,916 0 0 0 0
123 795 AAC 0 0 0 0 0 0 0
124 795 AAC 0 0 0 0 0 0 0
125 795 AAC 43,911 3,506,249 3,550,160 0 0 0 0
126 795 AAC 0 0 0 0 0 0 0
127 397.5 ACSR 0 0 0 0 0 0 0
128 1272 ACSR 140,412 2,602,119 2,742,531 0 0 0 0
129 1272 ACSR 0 0 0 0 0 0 0
130 795 ACSR 134,471 1,405,436 1,539,907 0 0 0 0
131 715.5 ACSR 2,473,833 19,000,082 21,473,915 0 0 0 0
132 715.5 ACSR 0 0 0 0 0 0 0
133 715.5 ACSR 0 0 0 0 0 0 0
134 715.5 ACSR 0 0 0 0 0 0 0
135 715.5 ACSR 0 0 0 0 0 0 0
136 1272 ACSR 78,579 2,219,508 2,298,087 0 0 0 0
137 40,580 0 40,580 0 0 0 0
138 715.5 ACSR 331,539 4,897,636 5,229,175 0 0 0 0
139 715.5 ACSR 0 0 0 0 0 0 0
140 715.5 ACSR 0 0 0 0 0 0 0
141 1272 ACSR 846,523 5,855,133 6,701,656 0 0 0 0
142 795 ACSR 0 0 0 0 0 0 0
143 795 ACSR 0 0 0 0 0 0 0
144 795 ACSR 0 0 0 0 0 0 0
145 795 ACSR 0 351,497 351,497 0 0 0 0
146 1272 ACSR 691,728 6,045,286 6,737,014 0 0 0 0
147 397.5 ACSR 0 94,004 94,004 0 0 0 0
148 250 COPPER 0 105,684 105,684 0 0 0 0
149 715.5 ACSR 1,174 267,313 268,487 0 0 0 0
150 1272 ACSR 327,334 2,143,350 2,470,684 0 0 0 0
151 1272 ACSR 0 0 0 0 0 0 0
152 795 ACSR 0 0 0 0 0 0 0
153 795 ACSR 0 0 0 0 0 0 0
154 795 ACSR 0 0 0 0 0 0 0
155 795 ACSR 0 (16,973)(16,973)0 0 0 0
156 1590 ACSR 0 60,659 60,659 0 0 0 0
157 715.5 ACSR 105,933 4,125,054 4,230,987 0 0 0 0
158 250 COPPER 58 65,525 65,583 0 0 0 0
159 715.5 ACSR 0 176,784 176,784 0 0 0 0
160 397.5 ACSR 0 4,797 4,797 0 0 0 0
161 715.5 ACSR 1,074 636,545 637,619 0 0 0 0
162 397.5 ACSR 6,332 2,566,179 2,572,511 0 0 0 0
163 715.5 ACSR 86,651 4,863,064 4,949,715 0 0 0 0
164 715.5 ACSR 0 0 0 0 0 0 0
165 715.5 ACSR 0 0 0 0 0 0 0
166 715.5 ACSR 7 295,569 295,576 0 0 0 0
167 715.5 ACSR 5,620 1,733,914 1,739,534 0 0 0 0
168 715.5 ACSR 14,968 183,606 198,574 0 0 0 0
169 397.5 ACSR 17,207 262,545 279,752 0 0 0 0
170 397.5 ACSR 1,978 68,812 70,790 0 0 0 0
171 VARIOUS 1,909,269 95,218,772 97,128,041 0 0 0 0
172 VARIOUS 0 0 0 0 0 0 0
173 VARIOUS 223,177 27,430,931 27,654,108 0 0 0 0
174 7,807,784 1,313,810 4,568,113 13,689,707
36 36,107,116 711,926,464 748,033,580 7,807,784 1,313,810 4,568,113 13,689,707
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
TRANSMISSION LINE STATISTICS
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
EXPENSES, EXCEPT
DEPRECIATION AND TAXES
EXPENSES, EXCEPT
DEPRECIATION AND
TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
Line
No.Size of Conductor and Material Land Construction Costs Total Costs Operation Expenses Maintenance Expenses Rents Total Expenses
(i)(j)(k)(l)(m)(n)(o)(p)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: TransmissionLineEndPoint
Page 422 Line 1: Borah-Midpoint- This line is jointly owned with PacifiCorp and Idaho Power owns 73.2% of this 85.4 mile line.
(b) Concept: TransmissionLineEndPoint
Page 422 Line 2:Boardman Slatt - This line is jointly owned with Portland General Electric and Idaho Power owns 10% of this 17.8 mile line.
(c) Concept: TransmissionLineEndPoint
Page 422 Line 3:Summer Lake Hemingway - This line is jointly owned with PacifiCorp and Idaho Power owns 22.0% of this 241.3 mile line.
(d) Concept: TransmissionLineEndPoint
Page 422 Line 4:Hemingway Midpoint - This line is jointly owned with PacifiCorp and Idaho Power owns 37.0% of this 129.3 mile line.
(e) Concept: TransmissionLineEndPoint
Page 422 Line 5:Summer Lake Hemingway - This line is jointly owned with PacifiCorp and Idaho Power owns 22.0% of this 241.3 mile line.
(f) Concept: TransmissionLineEndPoint
Page 422 Line 6:Hemingway Midpoint - This line is jointly owned with PacifiCorp and Idaho Power owns 37.0% of this 129.3 mile line.
(g) Concept: TransmissionLineEndPoint
Page 422 Line 7:Jim Bridger Goshen - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this 226.6 mile line.
(h) Concept: TransmissionLineEndPoint
Page 422 Line 9:Kinport Borah (Row 8) - This line is jointly owned with PacifiCorp and Idaho Power owns 73.2% of this 27.1 mile line.
(i) Concept: TransmissionLineEndPoint
Page 422 Line 10:Jim Bridger Populus - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this approximately 193 mile line.
(j) Concept: TransmissionLineEndPoint
Page 422 Line 11:Populus Kinport This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this 41.2 mile line.
(k) Concept: TransmissionLineEndPoint
Page 422 Line 12:Jim Bridger Populus - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this approximately 193 mile line.
(l) Concept: TransmissionLineEndPoint
Page 422 Line 13:Populus Borah - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this 47.3 mile line.
(m) Concept: TransmissionLineEndPoint
Page 422 Line 14:Goshen - Kinport - This line is jointly owned with PacifiCorp and Idaho Power owns 18.3% of this 40.9 mile line.
(n) Concept: TransmissionLineEndPoint
Page 422 Line 15:Midpoint Borah #1 - This line is jointly owned with PacifiCorp and Idaho Power owns 64.4% of this 79.5 mile line.
(o) Concept: TransmissionLineEndPoint
Page 422 Line 16:Midpoint Borah #2 - This line is jointly owned with PacifiCorp and Idaho Power owns 64.4% of this 77.9 mile line.
(p) Concept: TransmissionLineEndPoint
Page 422 Line 17:Adelaide Tap Adelaide - This line is jointly owned with PacifiCorp and Idaho Power owns 64.4% of this 0.9 mile line.
(q) Concept: TransmissionLineEndPoint
Page 422 Line 30:Boardman Dalreed Sub - This line is jointly owned with Portland General Electric and Idaho Power owns 10% of this 16.7 mile line.
(r) Concept: TransmissionLineEndPoint
Page 422 Line 44:Walla Walla - Hurricane - This line is jointly owned with PacifiCorp and Idaho Power owns 40.8% of this 77.6 mile line.
(s) Concept: TransmissionLineEndPoint
Page 422 Line 63:Goshen Stateline - This line is jointly owned with PacifiCorp. Idaho Power owns 37.8% of the Goshen Jefferson 28.9 mile segment, 37.8% of the Jefferson Big Grassy 20.8 mile segment and 100% of the Big Grassy Stateline 40.9 mile segment.
(t) Concept: TransmissionLineEndPoint
Page 422 Line 67:Antelope Goshen - This line is jointly owned with PacifiCorp and Idaho Power owns 21.9% of this 25.8 mile line.
(u) Concept: TransmissionLineEndPoint
Page 422 Line 68:Goshen Stateline - This line is jointly owned with PacifiCorp. Idaho Power owns 37.8% of the Goshen Jefferson 28.9 mile segment, 37.8% of the Jefferson Big Grassy 20.8 mile segment and 100% of the Big Grassy Stateline 40.9 mile segment.
(v) Concept: TransmissionLineEndPoint
Page 422 Line 69:Goshen Stateline - This line is jointly owned with PacifiCorp. Idaho Power owns 37.8% of the Goshen Jefferson 28.9 mile segment, 37.8% of the Jefferson Big Grassy 20.8 mile segment and 100% of the Big Grassy Stateline 40.9 mile segment.
(w) Concept: TransmissionLineEndPoint
Page 422 Line 148:Antelope - Scoville - This line is jointly owned with PacifiCorp and Idaho Power owns 11.5% of this 1 mile line.
(x) Concept: TransmissionLineEndPoint
Page 422 Line 149:American Falls Wheelon - This line is jointly owned with PacifiCorp and Idaho Power owns 7.2% of this 29.1 mile line.
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
TRANSMISSION LINES ADDED DURING YEAR
LINE DESIGNATION LINE DESIGNATION SUPPORTING
STRUCTURE SUPPORTING STRUCTURE CIRCUITS PER
STRUCTURE
Line
No.From To Line Length in Miles Type Average Number per Miles Present
(a)(b)(c)(d)(e)(f)
1 (a)
Shoshone Tap 21.27 H Wood 17 2
2 (b)
Boulder Tap 5.93 SP Steel 19 1
3 (c)
Cloverdale Hubbard 20.61 SP Steel 17 2
44 TOTAL (d)47.81 (e)53 5
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
TRANSMISSION LINES ADDED DURING YEAR
CIRCUITS PER STRUCTURE CONDUCTORS CONDUCTORS CONDUCTORS LINE COST
Line
No.Ultimate Size Specification Configuration and Spacing Voltage KV (Operating)Land and Land Rights
(g)(h)(i)(j)(k)(l)
1 2 397.5 ACSR Ibis TVS 138 19,540
2 1 715.5 ACSR Stilt TVS 138
3 2 1272 ACSR Bittern TAS, TVS 230 293,139
44 5 312,679
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
TRANSMISSION LINES ADDED DURING YEAR
LINE COST LINE COST LINE COST LINE COST
Line
No.Poles, Towers and Fixtures Conductors and Devices Asset Retire. Costs Total Construction
(m)(n)(o)(p)(q)
1 1,540,222 1,554,554 3,114,316
2 214,757 214,757
3 3,521,178 5,649,691 9,464,008
44 5,061,400 7,419,002 0 12,793,081
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: TransmissionLineStartPoint
Page 424 Line 1: Estimated amounts are reported
(b) Concept: TransmissionLineStartPoint
Page 424 Line 2: Estimated amounts are reported
(c) Concept: TransmissionLineStartPoint
Page 424 Line 3: Estimated amounts are reported
(d) Concept: LengthOfTransmissionLineAdded
Page 424 Column C:All Line Length in Miles and Average Number (per Miles) are reported in wire miles.
(e) Concept: AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles
Page 424 Column E:All Line Length in Miles and Average Number (per Miles) are reported in wire miles.
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)
VOLTAGE
(In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary
Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
1 (a)
Adelaide Transmission Unattended (u)345 (v)138 (w)13.8 (x)500
2 Aiken Distribution Unattended 46 13 27
3 Alameda Distribution Unattended 138 13 30
4 Alameda Distribution Unattended 138 13.09 30
5 American Falls PP Transmission Attended 138 13.8 120
6 American Falls Transmission Unattended 138 46 12.47 47
7
(b)
Antelope Transmission Unattended 230 161 13.8 224
8 (c)
Antelope Transmission Unattended 161 138 12.47 103
9 (d)
Antelope Transmission Unattended 161 138 13.8 92
10 Artesian Distribution Unattended 46 13 14
11 Bannock Creek Distribution Unattended 46 13 14
12 Beacon Light Distribution Unattended 138 13.09 45
13 Bennett Mountain Power Plant Transmission Attended 230 18 225
14 Bennett Mountain Power Plant Distribution Attended 18 4.16 5
15 Bethel Court Distribution Unattended 138 13 28
16 (e)
Big Grassy Transmission Unattended 161
17 Black Cat Distribution Unattended 138 13.09 90
18 Black Mesa Distribution Unattended 138 13 11
19 Blackfoot Distribution Unattended 46 13 56
20 Blackfoot Transmission Unattended 161 46 12.47 93
21 Blackfoot Distribution Unattended 161 138 12.98 135
22 Bliss Transmission Attended 138 13.8 86
23 Blue Gulch Distribution Unattended 138 35 48
24 Boise Bench Transmission Unattended 230 138 13.2 448
25 Boise Bench Distribution Unattended 138 35 30
26 Boise Bench Transmission Unattended 138 69 12.98 125
27 Boise Bench Transmission Unattended 230 138 13.8 448
28 Boise Bench Distribution Unattended 138 36.2 45
29 Boise Distribution Unattended 138 13 117
30 (f)
Borah Transmission Unattended 345 230 13.8 750
31 Border Distribution Unattended 138 12.47 11
32 Border Distribution Unattended 35 12.47 5
33 Boulder Distribution Unattended 138 35 30
34 Bowmont Distribution Unattended 138 35 30
35 Bowmont Transmission Unattended 138 69 12.98 46
36 Bowmont Transmission Unattended 138 69 12.47 47
37 Bowmont Transmission Unattended 230 138 13.8 600
38 Brady Transmission Unattended 230 138 13.8 312
39 Brady Transmission Unattended 138 46 12.47
40 Brady Distribution Unattended 46 13
41 Brady Distribution Unattended 46 7.2
42 Brownlee Transmission Attended 230 13.8 804
43 Bruneau Bridge Distribution Unattended 138 35 30
44 Bruneau Bridge Distribution Unattended 138 36.2 45
45 Buckhorn Distribution Unattended 69 35 37
46 Buhl Distribution Unattended 46 13.2
47 Burley Rural Distribution Unattended 69 13 20
48 Burley Rural Distribution Unattended 69 13.09 30
49 Butler Distribution Unattended 138 13.09 90
50 Caldwell Distribution Unattended 138 13 28
51 Caldwell Transmission Unattended 230 138 225
52 Caldwell Distribution Unattended 138 13.09 45
53 Caldwell Transmission Unattended 138 69 12.47 140
54 Caldwell Transmission Unattended 230 138 12.47 200
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
55 Camas Distribution Unattended 35 12.47 5
56 Camas Distribution Unattended 35 14.4 10
57 Can-Ada Distribution Unattended 138 13.09 45
58 Canyon Creek Distribution Unattended 138 36.2 45
59 Canyon Creek Transmission Unattended 138 69 12.98 20
60 Cartwright Distribution Unattended 138 13 11
61 Cascade Power Plant Transmission Attended 69 4.6 16
62 Cascade Distribution Unattended 69 13.09 7
63 Cascade Distribution Unattended 69 13.09 14
64 Cascade Distribution Unattended 25 12.5 5
65 Chestnut Distribution Unattended 138 13 45
66 Chestnut Distribution Unattended 138 13.09 45
67 Cinder Distribution Unattended 46 13 11
68 Clear Lake Transmission Attended 46 2.4 5
69 Cliff Transmission Unattended 138 46 12.5 21
70 Cliff Transmission Unattended 138 46 12.95 10
71 Cloverdale Distribution Unattended 138 13 90
72 Cloverdale Distribution Unattended 138 13.09 45
73 Cloverdale Transmission Unattended 230 138 13.8 300
74 Council Distribution Unattended 69 13 14
75 Crane Creek Distribution Unattended 69 13 11
76 Crater Distribution Unattended 46 13 11
77 Dale Distribution Unattended 46 4.6
78 Dale Distribution Unattended 46 13
79 Dale Distribution Unattended 69 13
80 Dale Distribution Unattended 138 36.2 45
81 Dale Transmission Unattended 138 46 12.47 47
82 Danskin Transmission Attended 230 18 233
83 Danskin Transmission Attended 230 138 13.8 300
84 Danskin Distribution Attended 18 4.16 6
85 Danskin Transmission Attended 138 12 160
86 Danskin Distribution Attended 35 13.8 5
87 Deen Distribution Unattended 46 13 11
88 Dietrich Distribution Unattended 46 13.09 14
89 Don Distribution Unattended 138 7.6
90 Don Distribution Unattended 138 13.2 180
91 Don Distribution Unattended 138 13 44
92 DRAM Distribution Unattended 138 13.09 168
93 DRAM Transmission Unattended 230 138 13.8 212
94 DRAM Distribution Unattended 138 12.47 28
95 DRAM Distribution Unattended 138 13 28
96 Duffin Distribution Unattended 138 35 60
97 Eagle Distribution Unattended 138 13.09 67
98 Eastgate Distribution Unattended 138 13.09 75
99 Eckert Distribution Unattended 138 36.2 30
100 Eden Distribution Unattended 138 36.2 45
101 Eden Transmission Unattended 138 46 12.98 20
102 Eldredge Distribution Unattended 138 13.09 45
103 Elkhorn Distribution Unattended 138 12.47 11
104 Elkhorn Distribution Unattended 138 13 11
105 Elmore Distribution Unattended 138 35 28
106 Elmore Transmission Unattended 138 69 12.5 25
107 Elmore Transmission Unattended 138 69 12.98 20
108 Emmett Distribution Unattended 138 13.09 45
109 Emmett Transmission Unattended 138 69 12.47 47
110 Falls Distribution Unattended 46 13 28
111 Filer Distribution Unattended 46 13 14
112 Flat Top Distribution Unattended 46 13 17
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)
VOLTAGE
(In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary
Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
113 Flying H Distribution Unattended 69 2.4 20
114 Fort Hall Distribution Unattended 46 13 14
115 Fossil Gulch Distribution Unattended 138 35 28
116 Fremont Transmission Unattended 138 46 12.5 67
117 Gary Distribution Unattended 138 13.09 37
118 Gary Distribution Unattended 138 13 28
119 Gem Distribution Unattended 69 13
120 Gem Distribution Unattended 69 13.09 28
121 Glenns Ferry Distribution Unattended 138 13 11
122 Gooding Rural Distribution Unattended 46 13 20
123 Golden Valley Distribution Unattended 69 13 14
124 (g)
Goshen Transmission Unattended 345 161 13.8 948
125 Gowen Substation Distribution Unattended 138 35 45
126 Gowen Substation Distribution Unattended 138 36.2 45
127 Grindstone Distribution Unattended 35 2.4 14
128 Grove Distribution Unattended 138 13.09 90
129 Grove Distribution Unattended 138 13 45
130 Hagerman Distribution Unattended 46 13 14
131 Hagerman Distribution Unattended 69 13 6
132 Hailey Distribution Unattended 138 13 37
133 Happy Valley Distribution Unattended 138 13.09 30
134 Haven Distribution Unattended 138 35 20
135 Haven Transmission Unattended 138 46 47
136 (h)
Hemingway Transmission Unattended 500 230 34.5 1000
137 Hewlett Packard Distribution Unattended 138 13 37
138 Hidden Springs Distribution Unattended 138 13 11
139 Highland Distribution Unattended 138 13 30
140 Hill Distribution Unattended 138 13 73
141 Hillsdale Distribution Unattended 138 13.09 45
142 Homedale Distribution Unattended 69 13 34
143 Horse Flat Transmission Unattended 230 138 13.8 100
144 Horseshoe Bend Distribution Unattended 35 13.09 7
145 Horseshoe Bend Distribution Unattended 69 36.2 22
146 Horseshoe Bend Distribution Unattended 69 25 7
147 Huston Distribution Unattended 69 13 14
148 Hulen Distribution Unattended 46 13 14
149 Hunt Transmission Unattended 230 138 13.8 336
150 Hydra Distribution Unattended 138 36.2 90
151 Island Distribution Unattended 69 13 20
152 (i)
Jefferson Transmission Unattended 161
153 Jerome Distribution Unattended 138 13 37
154 Jerome Distribution Unattended 138 13.09 37
155 Julion Clawson Distribution Unattended 138 35 56
156 Joplin Distribution Unattended 138 13 28
157 Joplin Distribution Unattended 138 36.2 45
158 Justice Transmission Unattended 230 138 13.8 300
159 Karcher Distribution Unattended 138 13 20
160 Kenyon Distribution Unattended 69 13 28
161 Ketchum Distribution Unattended 138 13 75
162 Kimberly Distribution Unattended 138 13.09 45
163 Kinport Transmission Unattended 161 46 13.2
164 Kinport Transmission Unattended 230 138 12.47 300
165 Kinport Transmission Unattended 230 138 13.8 300
166 (j)
Kinport Transmission Unattended 345 230 13.8 1000
167 Kramer Distribution Unattended 138 35 20
168 Kramer Distribution Unattended 138 36.2 30
169 Kuna Distribution Unattended 138 13.09 45
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)
VOLTAGE
(In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary
Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
170 Lake Distribution Unattended 69 13 14
171 Lake Fork Distribution Unattended 138 36.2 30
172 Lake Fork Transmission Unattended 138 69 12.5 20
173 Lamb Distribution Unattended 138 13 30
174 Langley Gulch Transmission Attended 230 138 13.8 636
175 Langley Gulch Transmission Attended 230 410
176 Langley Gulch Transmission Attended 230 150
177 Lansing Distribution Unattended 138 13.09 45
178 Lincoln Distribution Unattended 138 13.09 14
179 Linden Distribution Unattended 138 13 58
180 Locust Distribution Unattended 138 36.2 134
181 Locust Transmission Unattended 230 138 13.8 600
182 Lower Malad Transmission Attended 138 7.2 16
183 Lower Salmon Transmission Attended 138 13.8 70
184 Map Rock Distribution Unattended 69 13.09 14
185 McCall Distribution Unattended 138 13.09 22
186 McCall Distribution Unattended 138 36.2 30
187 Melba Distribution Unattended 69 13 11
188 Meridian Distribution Unattended 138 13 60
189 Micron Distribution Unattended 138 13.09 40
190 Micron Distribution Unattended 138 13 40
191 Midpoint Distribution Unattended 69 13
192 Midpoint Transmission Unattended 230 138 13.8 300
193 Midpoint Transmission Unattended 345 230 13.8 1400
194 (k)
Midpoint Transmission Unattended 500 345 1500
195 Midrose Distribution Unattended 138 13.09 45
196 Milner Transmission Unattended 138 69 12.47 125
197 Milner Distribution Unattended 69 46 6.9 8
198 Milner Distribution Unattended 138 35 50
199 Milner PP Transmission Attended 138 13.8 60
200 Moonstone Distribution Unattended 138 35 20
201 Mora Distribution Unattended 138 36.2 90
202 Moreland Distribution Unattended 46 36.2 28
203 Mountain Home Distribution Unattended 69 13 28
204 Mountain Home Air Force Base Distribution Unattended 69 13
205 Mountain Home Air Force Base Distribution Unattended 138 13 34
206 Nampa Transmission Unattended 230 138 13.8 300
207 Nampa Distribution Unattended 138 13 87
208 New Meadows Distribution Unattended 138 36.2 22
209 New Plymouth Distribution Unattended 69 13.09 14
210 Northview Distribution Unattended 138 13.09 45
211 Notch Butte Distribution Unattended 138 13.09 14
212 Orchard Distribution Unattended 69 36.2 41
213 Parma Distribution Unattended 69 13 14
214 Parma Distribution Unattended 69 35 22
215 Parma Distribution Unattended 69 36.2 14
216 Paul Distribution Unattended 138 35 30
217 Paul Distribution Unattended 138 36.2 45
218 Payette Distribution Unattended 138 13.09 45
219 Pingree Transmission Unattended 138 46 12.5 67
220 Pingree Distribution Unattended 138 35 34
221 Pleasant Valley Distribution Unattended 138 35 30
222 Pleasant Valley Distribution Unattended 138 36.2 45
223 Pocatello Distribution Unattended 46 13 60
224 Pocket Distribution Unattended 138 36.2 45
225 Poleline Distribution Unattended 138 13.09 30
226 (l)
Populus Transmission Unattended 345
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)
VOLTAGE
(In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary
Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
227 Portneuf Distribution Unattended 138 35 30
228 Portneuf Distribution Unattended 46 35
229 Rockford Distribution Unattended 46 13 25
230 Russett Distribution Unattended 138 13 30
231 Sailor Creek Distribution Unattended 138 2.4 21
232 Sailor Creek Distribution Unattended 138 35 28
233 Salmon Distribution Unattended 69 13.09 22
234 Salmon Distribution Unattended 69 36.2 22
235 Shoshone Distribution Unattended 46 13.09 14
236 Shoshone Distribution Unattended 46 7.2 2
237 Shoshone Transmission Unattended 138 46 12.47
238 Shoshone Falls Transmission Attended 46 4.16 4
239 Shoshone Falls Transmission Attended 46 6.6 14
240 Silver Distribution Unattended 138 35 20
241 Simplot Distribution Unattended 138 13 53
242 Sinker Creek Distribution Unattended 138 35 20
243 Siphon Distribution Unattended 138 36.2 75
244 Skyway Distribution Unattended 138 13.09 45
245 South Park Distribution Unattended 46 13 14
246 Spring Valley Distribution Unattended 138 12.47 11
247 Star Distribution Unattended 138 13.09 30
248 Starkey Transmission Unattended 138 69 12.47 30
249 State Distribution Unattended 69 13 58
250 Sterling Distribution Unattended 46 13 11
251 Stoddard Distribution Unattended 138 13 28
252 Strike Power Plant Transmission Attended 138 13.8 104
253 Sugar Distribution Unattended 138 35 28
254 Swan Falls Transmission Attended 138 6.9 34
255 Taber Distribution Unattended 46 13 6
256 Tamarack Distribution Unattended 138 2.4 11
257 Ten Mile Distribution Unattended 138 13.09 90
258 Terry Distribution Unattended 138 13.09 20
259 Terry Distribution Unattended 138 13 50
260 Thousand Springs Transmission Attended 46 7.2 8
261 (m)
Three Mile Knoll Transmission Unattended 345
262 Toponis Distribution Unattended 138 33 30
263 Twin Falls Distribution Unattended 138 13.09 82
264 Twin Falls Transmission Unattended 138 46 12.98 50
265 Twin Falls PP Transmission Attended 138 7.2 13
266 Twin Falls PP Transmission Attended 138 13.2 72
267 Tyhee Distribution Unattended 46 13 14
268 Upper Malad Transmission Attended 45 7.2 8
269 Upper Salmon Transmission Attended 138 7.2 42
270 Ustick Distribution Unattended 138 13 77
271 Vallivue Distribution Unattended 138 13.09 30
272 Victory Distribution Unattended 138 13 45
273 Victory Distribution Unattended 138 13.09 30
274 Ware Distribution Unattended 69 13 20
275 Weiser Distribution Unattended 69 13 28
276 Weiser Transmission Unattended 138 69 12.47 42
277 Wilder Distribution Unattended 69 13 14
278 Willis Distribution Unattended 138 13.09 30
279 Willow Creek Distribution Unattended 138 13 11
280 Wye Distribution Unattended 138 13 60
281 Wye Distribution Unattended 138 13.09 37
282 Zilog Distribution Unattended 138 13.09 45
283 The above are all State of Idaho
284 State of Montana:
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)
VOLTAGE
(In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary
Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
285 (n)
Mill Creek Transmission Unattended 230
286 Peterson Transmission Unattended 230 69 13.2 56
287 State of Nevada
288 (o)
Valmy Transmission Attended 345 18 315
289 Wells Transmission Unattended 138 69 13 25
290 State of Oregon
291 Adrian Distribution Unattended 69 13 11
292 (p)
Burns Transmission Unattended 500
293 Cairo Distribution Unattended 69 13 20
294 Hells Canyon Transmission Attended 230 13.8 560
295 Hells Canyon Distribution Attended 69 0.5 1
296 Hines Transmission Unattended 138 115 12.47 80
297 Holly Distribution Unattended 69 13.09 14
298 (q)
Hurricane Transmission Unattended 230
299 Jacobson Gulch Distribution Unattended 69 2.4 11
300 Malheur Butte Distribution Unattended 69 34.5 11
301 Nyssa Distribution Unattended 69 13 28
302 Ontario Distribution Unattended 138 13 67
303 Ontario Transmission Unattended 138 69 12.47 47
304 Ontario Transmission Unattended 230 138 13.8 400
305 Ontario Transmission Unattended 138 69 12.98 93
306 Ontario Transmission Unattended 138 69 13.09
307 Ontario Transmission Unattended 138 69 12.5
308 Ore-Ida Distribution Unattended 69 13 28
309 Oxbow Transmission Attended 138 69 13 13
310 Oxbow Transmission Attended 230 13.8 274
311 Oxbow Transmission Attended 230 138 13.8 100
312 Quartz Transmission Unattended 138 69 12.5 25
313 Quartz Transmission Unattended 230 138 12.98 167
314 Quartz Transmission Unattended 138 69 12.98 20
315
(r)
Summer Lake Transmission Unattended 500
316 Vale Distribution Unattended 69 13 14
317 State of Washington:
318 (s)
Walla Walla Transmission Unattended 230
319 State of Wyoming:
320 (t)
Jim Bridger Transmission Attended 345 22 34.5 2244
321 Transformers-distribution substations under 10,000
322 KVA 61 unattended.Distribution Unattended 208
323 Distribution Substations 22,512 3,982.1400 19.8800 7,173
324 Distribution Substations Attended 140 22.62 0 17
325 Distribution Substations Unattended 22,372 3,959.5200 19.8800 7,156
326 Transmission Substations 19,893 7,483.2600 881.8800 21,813
327 Transmission Substations Attended 4,944 905.26 88.9 6,946
328 Transmission Substations Unattended 14,949 6,578 792.9800 14,867
329 Total 28,986
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)
VOLTAGE
(In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary
Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
1 2
2 2
3 1
4 1
5 1
6 1
7 1
8 1
9 1
10 1
11 1
12 1
13 1
14 1
15 1
16
17 2
18 1
19 2
20 3 1
21 1
22 3
23 2
24 2
25 1
26 3
27 2
28 1
29 3
30 3 1
31 1
32 3
33 1
34 1
35 1
36 1
37 2
38 3
39 1
40 5
41 2
42 5 1
43 1
44 1
45 1
46 1
47 1
48 1
49 2
50 1
51 1
52 1
53 3
54 1
55 3 1
56 3 1
57 1
58 1
59 1
60 1
61 1
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
62 1
63 1
64 1
65 1
66 1
67 1
68 1
69 2 1
70 1
71 2
72 1
73 1
74 1
75 1
76 1
77 1
78 7
79 1
80 1
81 1
82 1
83 1
84 1
85 2
86 1
87 1
88 1
89 1
90 6 1
91 1
92 6
93 2
94 1
95 1
96 2
97 2
98 2
99 1
100 1
101 1
102 1
103 1
104 1
105 1
106 1
107 1
108 1
109 1
110 2
111 1
112 2
113 2
114 1 1
115 1
116 3 1
117 1
118 1
119 2
120 2
121 1
122 2
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
123 1 1
124 5
125 1
126 1
127 2
128 2
129 1
130 1
131 1
132 1
133 1
134 1
135 1
136 3 1
137 1
138 1
139 1
140 2
141 1
142 2
143 1
144 1
145 1
146 1
147 1
148 1
149 3
150 2
151 1
152
153 1
154 1
155 2
156 1
157 1
158 1
159 1
160 2
161 2
162 1
163 7
164 1
165 1
166 3 1
167 1
168 1
169 1
170 1
171 1
172 1
173 1
174 2
175 2
176 1
177 1
178 1
179 2
180 3
181 2
182 1
183 4
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
184 1
185 1
186 1
187 1
188 2
189 2
190 2
191 2
192 1 1
193 2 1
194 3 1
195 1
196 3 1
197 3 1
198 2
199 1
200 1
201 2
202 2
203 1
204 1
205 1
206 1
207 3
208 1
209 1
210 1
211 1
212 2
213 1
214 1
215 1
216 1 1
217 1
218 1
219 3
220 2
221 1
222 1
223 2
224 1
225 1
226
227 1
228 1
229 2
230 1
231 2
232 1
233 1
234 1
235 1
236 3
237 1
238 1
239 1
240 1
241 2
242 1
243 2
244 1
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
245 1
246 1
247 1
248 1
249 2
250 2
251 1
252 3
253 2
254 1
255 1
256 1
257 2
258 1
259 2
260 1
261
262 1
263 2
264 2
265 1
266 1
267 1
268 1
269 4
270 2
271 1
272 1
273 1
274 1 1
275 2
276 1
277 1
278 1
279 1
280 2
281 1
282 1
283
284
285
286 1 1
287
288 1
289 3 1
290
291 1
292
293 1
294 3
295 1
296 1 1
297 1
298
299 1
300 3 1
301 2
302 2 1
303 1
304 2
305 2
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
306 1
307 1
308 1
309 3 1
310 2
311 1
312 1
313 3 1
314 1
315
316 1
317
318
319
320 4
321
322
323 277 34 0 0
324 4 0 0 0
325 273 34 0 0
326 154 28 0 0
327 54 3 0 0
328 100 25 0 0
329
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Adelaide station. Ownership interest varies by terminal. 100% of the capacity is reported.
(b) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Antelope station. Ownership interest varies by terminal. 100% of the capacity is reported.
(c) Concept: SubstationNameAndLocation
Jointly owned with PacifiCorp, Idaho Power has 66.7% share of ownership. 100% of the capacity is reported.
(d) Concept: SubstationNameAndLocation
Jointly owned with PacifiCorp, Idaho Power has 66.7% share of ownership. 100% of the capacity is reported.
(e) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Big Grassy station. Ownership interest varies by terminal.
(f) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Borah station. Ownership interest varies by terminal. 100% of the capacity is reported.
(g) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Goshen station. Ownership interest varies by terminal. 100% of the capacity is reported.
(h) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Hemingway station. Ownership interest varies by terminal. 100% of the capacity is reported.
(i) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Jefferson station. Ownership interest varies by terminal.
(j) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Kinport station. Ownership interest varies by terminal. 100% of the capacity is reported.
(k) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Midpoint station. Ownership interest varies by terminal. 100% of the capacity is reported.
(l) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Populus station. Ownership interest varies by terminal.
(m) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Three Mile Knoll station. Ownership interest varies by terminal.
(n) Concept: SubstationNameAndLocation
Idaho Power has 32% ownership in certain transmission related equipment located at Northwestern Energy's Mill Creek Station.
(o) Concept: SubstationNameAndLocation
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50% share of ownership. 100% of the capacity reported.
(p) Concept: SubstationNameAndLocation
Idaho Power has a 22% ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Burns station.
(q) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Hurricane station. Ownership interest varies by terminal.
(r) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Summer Lake station. Ownership interest varies by terminal.
(s) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Walla Walla station. Ownership interest varies by terminal.
(t) Concept: SubstationNameAndLocation
Jointly owned with PacifiCorp. Idaho Power has a 33.3% share of ownership. 100% of the capacity is reported.
(u) Concept: PrimaryVoltageLevel
For all of column c: Primary voltages reported in KV unless otherwise noted.
(v) Concept: SecondaryVoltageLevel
For all of column d: Secondary voltages reported in KV unless otherwise noted.
(w) Concept: TertiaryVoltageLevel
For all of column e: Tertiary voltages reported in KV unless otherwise noted.
(x) Concept: SubstationInServiceCapacity
For all of column f: Top rating capacity reported unless otherwise noted.
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/15/2022
Year/Period of Report
End of: 2021/ Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Line
No.
Description of the Good or Service
(a)
Name of Associated/Affiliated Company
(b)
Account(s) Charged or
Credited
(c)
Amount Charged or Credited
(d)
1 Non-power Goods or Services Provided by Affiliated
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliated
21 Managerial Expenses 417420 IDACORP, INC.417420 487,600
22 Managerial Expenses 922000 IDACORP, INC.922000 29,847
42
FERC FORM NO. 1 ((NEW))
Page 429
December 31, 2021
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI-STATE ELECTRIC COMPANIES
INDEX
Page
Number Title
1 Statement of Income for the Year
2 Taxes Allocated to Idaho
3 Notes and Accounts Receivable
3 Accumulated Provision for Uncollectible Accounts
4 Receivables from Associated Companies
5 Gain or Loss on Disposition of Property
6 Professional or Consultative Services
7-10 Electric Plant in Service
11 Electric Operating Revenues
12-15 Electric Operation and Maintenance Expenses
15 Number of Electric Department Employees
IDAHO SUPPLEMENT
December 31, 2021
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate.
Include these amounts in columns (c) and (d) totals.
2. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
3. Report data for lines 7, 9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1, and 407.2.
4. Use page 122 for important notes regarding the state ment of income or any account thereof.
5. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant amounts of any refunds made or received during the year.
(Ref.)
Line Account Page TOTAL
No.No.Current Year Previous Year
(a)(b)(c)(d)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400).................................................................................................................................................................xxx111,388,475,677$ 1,284,238,508$
3 Operating Expenses
4 Operation Expenses (401)...............................................................................................................................................................xxx15807,748,455 733,790,307
5 Maintenance Expenses (402).................................................................................................................................................................xxx1564,276,452 56,215,074
6 Depreciation Expense (403)..............................................................................................................................................................xxx158,708,540 155,941,941
7 Amort. & Depl. of Utility Plant (404-405)...............................................................................................................................................xxx8,153,605 7,428,416
8 Amort. of Utility Plant Acq. Adj. (406)...............................................................................................................................................xxx
9 Amort. of Property Losses, Unrecovered Plant and
10 Accretion Expense (411).........................................................................54,557 169,064
11 Regulatory Study Costs (407).........................................................................................................................................................xxx
12 Amort. of Conversion Expenses (407)...................................................................................................................................................xxx
13 Regulatory Debits/Credits (407.3 & 407.4)...................................................................................................................................................................................xxx1,219,115 1,075,354
14 Taxes Other Than Income Taxes (408.1)..................................................................................................................................................xxx228,778,496 30,879,247
15 Income Taxes - Federal (409.1).........................................................................................................................................................xxx234,389,338 25,454,806
16 - Other (409.1)...........................................................................................................................................................xxx213,053,377 6,109,267
17 Provision for Deferred Income Taxes (410.1 & 411.1) Net…………………………………………..2 (20,863,440)(5,973,440)
18 Investment Tax Credit Adj. - Net (411.4).................................................................................................................................................xxx211,353,062 2,710,641
19 (Less) Gains from Disp. of Utility Plant (411.6).........................................................................................................................................xxx
20 Losses from Disp. of Utility Plant (411.7)..............................................................................................................................................xxx
21 (Less) Gains from Disposition of Allowances (411.8).....................................................................................................................................................xxx
22 Losses from Disposition of Allowances (411.9).....................................................................................................................................................xxx
23
24 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22)....................................................................................................................xxx1,106,871,556 1,013,800,677
25
26
27 Net Utility Operating Income (Enter Total of line 2 less 24)………………….281,604,122$ 270,437,830$
Page 1
IDAHO SUPPLEMENT
December 31, 2021
TAXES ALLOCATED TO IDAHO
Taxes Charged
Kind of Tax During Year
Taxes Other Than Income Taxes:
Labor Related:
FICA..................................................................................................................................................xxx16,137,135$
FUTA..................................................................................................................................................xxx87,162
State Unemployment....................................................................................................................................xxx206,772
Payroll Deduction & Loading......................(16,431,069)
Total Labor Related......................................................................................................................................xxx0
Property Taxes...........................................................................................................................................xxx25,111,116
Kilowatt-hour Tax........................................................................................................................................xxx1,062,709
Licenses.................................................................................................................................................xxx3,849
Regulatory Commission Fees...............................................................................................................................xxx2,402,308
Irrigation PIC...........................................................................................................................................xxx198,514
Canada Sales Tax...........................................................................................................................................xxx0
Total Taxes Other Than Income Taxes........................................................................................................................xxx28,778,496
Federal Income Taxes.......................................................................................................................................xxx34,389,338
State Income Taxes.........................................................................................................................................xxx13,053,377
Deferred Income Taxes......................................................................................................................................xxx(20,863,440)
Investment Tax Credit Adjustment - Net.....................................................................................................................xxx11,353,062
Total Taxes Allocated to Idaho.............................................................................................................................xxx66,710,832$
Page 2
IDAHO SUPPLEMENT
December 31, 2021
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
from directors, officers, and employees included in Notes Receivable (Account
141) and Other Accounts Receivable (Account 143)
Balance Balance
Line Accounts Beginning of End of
Year Year
No. (a)(b)(c)
1 Notes Receivable (Account 141)....................................................................................................................................................xxx-$ -$
2 Customer Accounts Receivable (Account 142)........................................................................................................................................xxx77,599,924 83,325,175
3 Other Accounts Receivable (Account 143)...........................................................................................................................................xxx10,223,384 12,806,869
4 (Disclose any capital stock subscription received)
5 Total......................................................................................................................................87,823,308$ 96,132,043$
6
7 Less: Accumulated Provision for Uncollectible
8 Accounts-Cr. (Account 144)..............................................................................5,263,704 5,015,917
9
10 Total, Less Accumulated Provision for
11 Uncollectible Accounts.....................................................................................................................................................xxx82,559,604$ 91,116,126$
12
13
14
15
16
17
18
19
20
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report below the information called for concerning this accumulated provision.
2. Explain any important adjustments of subaccounts.
3. Entries with respect to officers and employees shall not include items for utility services.
Mdse,
Line Item Utility Jobbing &Officers Other Total
Customers Contract and
No.(a)Work Employees
(b)(c)(d)(e)(f)
21 Balance Beg of Year:5,263,704$ 5,263,704$
22 -$
23 Uncollectible Retail Electric Sales (267,031)$ $ (267,031)$
24
25 Uncollectible Damage Claims 19,244 19,244$
26
27 Uncollectibe Other Revenues --$
28
29
30
31
32 Balance end of year........................................................................................................................xxx5,015,917$ -$ -$ -$ 5,015,917$
33
Page 3
IDAHO SUPPLEMENT
December 31, 2021
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, 146)
1. Report particulars of notes and accounts receivable from associated companies at end of year.
2. Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3. For notes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate.
4. If any note was received in satisfaction of an open account, state the period covered by such open account.
5. Include in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account.
Balance
Line Particulars Beginning Totals for Year Balance Interest
of Year Debits Credits End of Year For Year
No.(a)(b)(c)(d)(e)(f)
1 Account 145:
2
3 IERCO……………………….10,088,722$ 51,265,327$ 55,184,504$ 6,169,545$
4
5
6
7
8
9
10 Total Account 145………………..10,088,722 51,265,327 55,184,504 6,169,545
11
12 Account 146:
13
14
15
16 IDACORP, Inc……………….-$ 6,306,454$ 6,306,454$ -$
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Total Account 146.....................................................................................................................xxx-$ 6,306,454$ 6,306,454$ -$
32
Page 4
IDAHO SUPPLEMENT
December 31, 2021
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421.2)
1. Give a brief description of property creating the gain or loss. Include name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed. Identify property
by type; Leased, Held for Future Use, or Nonutility.
2. Individual gains or losses relating to property with an original cost of less than $50,000 may be grouped, with the
number of such transactions disclosed in column (a).
3. Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Original Cost Date Journal
Line Description of Property of Related Entry Approved Acct 421.1 Acct 421.2
(When Required)
No.(a)(b)(c)(d)(e)
1 Gain on disposition of property
2 property: -$ -$ $
3
4 Hillsdale Substation 1,588.94$ (7,217.41)$
5 partial land disposal to highway district
6
7
8
9
10
11
12
13
14
15
16 Total gain....................................................................................................................................................xxx1,588.94$ (7,217.41)$ -$
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Total loss......................................................................................................................................................xxx0$ 0$ 0$
Page 5
IDAHO SUPPLEMENT
December 31, 2021
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
1 ADM Energy Consulting 59,858.00
2 ACCRUENT LLC Management Services 27,043.75
3 ADAMS COUNTY SHERIFF'S OFFICE Management Services 15,000.00
4 AGREE TECHNOLOGIES AND SOLUTIO IT Services 57,359.00
5 ALLPHIN, RANDY C Management Services 13,065.00
6 AUTOSORT Management Services 47,334.00
7 BAKER BOTTS LLP Legal Services 410,547.96
8 BARKER, ROSHOLT & SIMPSON LLP Legal Services 262,095.87
9 BLACK & VEATCH MANAGEMENT CONS Management Services 190,977.50
10 BROWN AND CALDWELL Legal Services 20,255.00
11 CLEAREDGE PARTNERS Training Consultants 105,000.00
12 COMPUNET, INC Legal Services 83,805.00
13 DAVIS WRIGHT TREMAINE LLP Legal Services 27,524.40
14 DELOITTE TAX LLP Tax Services 19,885.00
15 DNV ENERGY SERVICES USA INC Management Services 1,001,781.62
16 EQ SHAREOWNER SERVICES Management Services 103,929.28
17 EVERGREEN CONSULTING GROUP, LL Management Services 324,963.58
18 EXPONENT, INC Management Services 18,550.48
19 EXPRESS MANAGED SERVICES Management Services 32,869.89
20 FORRESTER RESEARCH, INC.IT Services 60,000.00
21 FRESHWATER TRUST, THE Environmental Services 164,493.97
22 GIVENS PURSLEY LLP Legal Services 112,288.00
23 HAWLEY TROXELL ENNIS & HAWLEY Legal Services 71,419.35
24 HEPLERBROOM LLC Legal Services 10,007.54
25 HOLLAND & HART LLP Legal Services 92,516.70
26 ICEBERG NETWORKS CORPORATION IT Services 55,737.50
27 J J KELLER & ASSOCIATES I Legal Services 10,000.00
28 J M ROCHE AND ASSOCIATES Legal Services 12,157.76
29 JENSEN HUGHES Consulting 20,735.37
30 KIRTON MCCONKIE Legal Services 202,566.81
31 KW ENGINEERING INC Engineering Consultants 35,377.77
32 MCDOWELL RACKNER & GIBSON PC Legal Services 2,128,268.43
33 MEDIANT COMMUNICATIONS INC Manament 37,199.41
34 MORROW & FISCHER PLLC Legal Services 21,380.58
35 NEDERVELD INC IT Services 13,030.37
36 NIELSEN GROUP INC, THE IT Services 180,249.35
37 PARSONS BEHLE & LATIMER Legal Services 41,855.00
38 PERKINS COIE LLP Legal Services 402,175.91
39 QUALITY COMMUNICATIONS INC IT Services 76,377.50
40 REED HARRIS ENVIRONMENTAL LTD Environmental Services 21,435.00
41 RESOLUTION STRATEGIES LLP IT Services 38,389.03
42 RESOURCE DATA, INC IT Services 104,835.00
43 RM ENERGY CONSULTING Energy Consulting 240,068.95
44 ROCK CREEK ENERGY GROUP LLP Legal Services 52,857.73
Page 6
IDAHO SUPPLEMENT
December 31, 2021
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
45 STOEL RIVES LLP Legal Services 174,324.37
46 TETRA TECH INC Consulting Services 70,492.00
47 TUCKER, JAMES C Consulting Services 46,337.50
48 U S ARMY ENGINEER AND DEVELOPM Management Services 51,969.80
49 UNIVERSITY OF IDAHO Management Services 213,673.63
50 VAN NESS FELDMAN LLP Legal Services 441,960.90
51 WILLIS TOWERS WATSON US LLC Management Services 11,900.00
52 WITHERSPOON KELLEY Legal Services 70,361.75
53 YTURRI& ROSE& BURNHAM& BENTZ Management Services 16,597.50
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
TOTAL 8,124,886$
Page 6A
IDAHO SUPPLEMENT
December 31, 2021
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5,000 OR MORE BUT LESS THAN $10,000
Line PREDOMINANT
No.PAYEE NATURE OF SERVICE AMOUNT
1 ABBOTT, STRINGHAM, & LYNCH Legal Services 9,000
2 AVTEC INC IT Services 8,964
3 CCRCORP Legal Services 6,225
4 CLARK WARDLE LLP Legal Services 8,980
5 CRAPO DEEDS PLLC Tax Services 6,086
6 GARTNER GROUP Management Services 5,386
7 HOLTON ENTERPRISES INC Construction Services 7,500
8 J J KELLER & ASSOCIATES I Safety Consultants 10,000
9 KEANE Management Services 6,210
10 LEONARD PETROLEUM EQUIPMENT Construction Services 8,075
11 PROFESSIONAL TRAINING SYSTEMS Training Services 5,768
12 RIGHT SYSTEMS, INC IT Services 9,900
13 SHUPE, DR TODD Health and Safety Consultations 5,000
14 SOVOS COMPLIANCE LLC Tax Services 5,400
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 102,493$
Page 6B
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in
column (c) . Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in
column (b). Likewise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful ob-
servance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
Line Account Beginning of year Additions
No.(a)(b)(c)
1 1. INTANGIBLE PLANT
2 (301) Organization......................................................................................................................................................xxx5,480$
3 (302) Franchises and Consents...........................................................................................................................................xxx33,796,192
4 (303) Miscellaneous Intangible Plant...................................................................................................................................xxx39,393,526
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)...............................................................................................................xxx73,195,198
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights..............................................................................................................................................xxx
9 (311) Structures and Improvements.......................................................................................................................................xxx
10 (312) Boiler Plant Equipment...........................................................................................................................................xxx
11 (313) Engines and Engine Driven Generators..............................................................................................................................xxx
12 (314) Turbogenerator Units......................................................................................................................................................xxx
13 (315) Accessory Electric Equipment...........................................................................................................................................xxx
14 (316) Misc. Power Plant Equipment......................................................................................................................................xxx
15 (317) Asset Retirement Costs for Steam Production……………… …………………..14,856,097
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15).....................................................................................................................xxx950,199,978
17 B. Nuclear Production Plant
18 (320) Land and Land Rights.............................................................................................................................................xxx
19 (321) Structures and Improvements.......................................................................................................................................xxx
20 (322) Reactor Plant Equipment...........................................................................................................................................xxx
21 (323) Turbogenerator Units...............................................................................................................................................xxx
22 (324) Accessory Electric Equipment.......................................................................................................................................xxx
23 (325) Misc. Power Plant Equipment......................................................................................................................................xxx
24 (326) Asset Retirement Costs for Nuclear Production………………..…………………
25 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 24)...............................................................................................................xxx
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights...............................................................................................................................................xxx
28
29 (332) Reservoirs, Dams, and Waterways....................................................................................................................................xxx
30 (333) Water Wheels, Turbines, and Generators...............................................................................................................................xxx
31 (334) Accessory Electric Equipment.....................................................................................................................................xxx
32 (335) Misc. Power Plant Equipment......................................................................................................................................xxx
33 (336) Roads, Railroads, and Bridges....................................................................................................................................xxx
34 (337) Asset Retirement Costs for Hydraulic Production………………..…………………
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34).....................................................................................................xxx950,747,321
36 D. Other Production Plant
37 (340) Land and Land Rights.............................................................................................................................................xxx
38 (341) Structures and Improvements......................................................................................................................................xxx
39 (342) Fuel Holders, Products and Accessories............................................................................................................................xxx
40 (343) Prime Movers.....................................................................................................................................................xxx
41 (344) Generators........................................................................................................................................................xxx
42 (345) Accessory Electric Equipment.......................................................................................................................................xxx
43 (346) Misc Power Plant Equipment.......................................................................................................................................xxx
Page 7
IDAHO SUPPLEMENT
December 31, 2021
Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column
(f) the additions or reductions of primary account classifications arising from distribution of amounts
initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
Retirements Adjustments Transfers End of Year Line
(d)(e) (f) (g)No.
1
5,472$ (301)2
36,559,366 (302)3
42,707,437 (303)4
79,272,275 5
6
7
(310)8
(311)9
(312)10
(313)11
(314)12
(315)13
(316)14
25,482,471 (317)15
970,930,307 16
17
(320)18
(321)19
(322)20
(323)21
(324)22
(325)23
(326)24
25
26
(330)27
(331)28
(332)29
(333)30
(334)31
(335)32
(336)33
(337)34
990,128,902 35
36
(340)37
(341)38
(342)39
(343)40
(344)41
(345)42
(345)43
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Page 8
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Line Balance at
Account Beginning of year Additions
No.(a) (b)(c)
44 (346) Misc. Power Plant Equipment.....................................................................................................................................xxx
45 TOTAL Other Production Plant (Enter Total of lines 37 thru 44)..........................................................................................................xxx532,054,400$
46 TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)..............................................................................................................xxx2,433,001,698
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights..............................................................................................................................................xxx37,655,709
49 (352) Structures and Improvements........................................................................................................................................xxx82,257,848
50 (353) Station Equipment..................................................................................................................................................xxx444,601,459
51 (354) Towers and Fixtures................................................................................................................................................xxx214,331,374
52 (355) Poles and Fixtures..................................................................................................................................................xxx209,028,945
53 (356) Overhead Conductors and Devices......................................................................................................................................xxx235,379,556
54 (357) Underground Conduit...................................................................................................................................................xxx
55 (358) Underground Conductors and Devices.................................................................................................................................xxx
56 (359) Roads and Trails..................................................................................................................................................xxx375,347
57 (359.1) Asset Retirement Costs for Transmission Plant………………..…………………
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57).............................................................................................................xxx1,223,630,237
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights................................................................................................................................................xxx7,238,993
61 (361) Structures and Improvements........................................................................................................................................xxx49,083,482
62 (362) Station Equipment...................................................................................................................................................xxx276,661,985
63 (363) Storage Battery Equipment...........................................................................................................................................xxx
64 (364) Poles, Towers, and Fixtures.......................................................................................................................................xxx270,080,950
65 (365) Overhead Conductors and Devices.........................................................................................................................................xxx137,873,958
66 (366) Underground Conduit.................................................................................................................................................xxx52,771,795
67 (367) Underground Conductors and Devices....................................................................................................................................xxx298,363,317
68 (368) Line Transformers....................................................................................................................................................xxx624,839,833
69 (369) Services.............................................................................................................................................................xxx61,940,066
70 (370) Meters..............................................................................................................................................................xxx101,393,772
71 (371) Installations on Customer Premises................................................................................................................................xxx3,760,088
72 (372) Leased Property on Customer Premises................................................................................................................................xxx
73 (373) Street Lighting and Signal Systems.................................................................................................................................xxx4,634,074
74 (374) Asset Retirement Costs for Distribution Plant………………..…………………
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)...................................................................................................................xxx1,888,642,313
76 5. GENERAL PLANT
77 (389) Land and Land Rights..................................................................................................................................................xxx18,125,089
78 (390) Structures and Improvements...........................................................................................................................................xxx130,988,159
79 (391) Office Furniture and Equipment........................................................................................................................................xxx42,004,990
80 (392) Transportation Equipment..............................................................................................................................................xxx108,866,067
81 (393) Stores Equipment......................................................................................................................................................xxx4,211,969
82 (394) Tools, Shop, and Garage Equipment....................................................................................................................................xxx11,796,142
83 (395) Laboratory Equipment................................................................................................................................................xxx14,278,331
84 (396) Power Operated Equipment...........................................................................................................................................xxx22,779,950
85 (397) Communication Equipment...............................................................................................................................................xxx58,153,549
86 (398) Miscellaneous Equipment.............................................................................................................................................xxx7,828,949
87 SUBTOTAL (Enter Total of lines 77 thru 86)..........................................................................................................................xxx419,033,194
88 (399) Other Tangible Property...........................................................................................................................................xxx
89 (399.1) Asset Retirement Costs for General Plant………………..…………………
90 TOTAL General Plant (Enter Total of lines 87, 88 and 89)....................................................................................................................xxx419,033,194
91 TOTAL (Accounts 101 and 106)....................................................................................................................................xxx6,037,502,640
92 (102) Electric Plant Purchased ..........................................................................................................................................xxx
#REF!
#REF! TOTAL Electric Plant in Service.......................................................................................................................................xxx6,037,502,640$
Page 9
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Balance at Line
Retirements Adjustments Transfers End of Year
(d)(e) (f) (g)No.
(346)44
532,713,240$ 45
2,493,772,449 46
47
38,038,072 (350)48
83,986,744 (352)49
451,357,571 (353)50
222,111,189 (354)51
215,197,387 (355)52
245,813,303 (356)53
(357)54
(358)55
374,713 (359)56
(359.1)57
1,256,878,979 58
59
7,640,364 (360)60
49,536,165 (361)61
288,442,652 (362)62
(363)63
282,980,841 (364)64
143,391,424 (365)65
52,525,989 (366)66
308,886,276 (367)67
658,856,816 (368)68
63,794,607 (369)69
106,387,667 (370)70
4,953,808 (371)71
(372)72
5,320,596 (373)73
(374)74
1,972,717,206 75
76
19,851,492 (389)77
135,415,417 (390)78
41,259,844 (391)79
104,860,168 (392)80
4,105,787 (393)81
11,855,992 (394)82
14,180,032 (395)83
22,957,093 (396)84
78,043,602 (397)85
9,795,834 (398)86
442,325,261 87
(399)88
(399.1)89
442,325,261 90
6,244,966,169 91
(102)92
93
6,244,966,169$ 94
Page 10
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC OPERATING REVENUES (Account 400)
1. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e) and (g), are not derived from previously reported figures, explain any
inconsistencies in a footnote.
OPERATING REVENUES
Amount for Amount for
No.Current Year Previous Year
(a)(b)(c)
1 Sales of Electricity
2 (440) Residential Sales............................................................................................................................................xxx567,032,561$ 532,085,463$
3 (442) Commercial and Industrial Sales
4 Small (or Commercial)(See Instr. 4) (1)............................................................................................................................xxx461,736,010 427,454,427
5 Large (or Industrial)(See Instr. 4) (2)..............................................................................................................................xxx179,498,602 165,501,103
6 (444) Public Street and Highway Lighting................................................................................................................................xxx3,797,771 3,669,473
7 (445) Other Sales to Public Authorities.................................................................................................................................xxx
8 (446) Sales to Railroads and Railways..................................................................................................................................xxx
9 (448) Interdepartmental Sales........................................................................................................................................xxx
10 TOTAL Sales to Ultimate Consumers................................................................................................................................xxx1,212,064,944 *1,128,710,466
11 (447) Sales for Resale - Opportunity.…Non-Firm Only........................................................................................................................xxx86,431,325 63,135,738
12 TOTAL Sales of Electricity....................................................................................................................................xxx1,298,496,269 1,191,846,204
13 (449) Provision for Rate Refunds............................................................................................................................xxx(13,699,093)(12,151,500)
14 TOTAL Revenue Net of Provision for Refunds........................................................................................................................xxx1,284,797,176 1,179,694,705
15 Other Operating Revenues
16 (450) Forfeited Discounts........................................................................................................................................xxx
17 (451) Miscellaneous Service Revenues..................................................................................................................................xxx4,613,049 4,308,346
18 (453) Sales of Water and Water Power................................................................................................................................xxx
19 (454) Rent from Electric Property.....................................................................................................................................xxx17,583,812 16,719,368
20 (455) Interdepartmental Rents........................................................................................................................................xxx
21 (456) Other Electric Revenues.........................................................................................................................................xxx81,481,640 83,516,089
22
23
24
25 TOTAL Other Operating Revenues...................................................................................................................................xxx103,678,502 104,543,803
26 TOTAL Electric Operating Revenues..............................................................................................................................xxx1,388,475,677$ 1,284,238,508$
(1) Commercial and Industrial sales - Small - under 1,000 KW and includes all irrigation customers.
(2) Commercial and Industrial sales - Large - 1,000 KW and over.
Page 11
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
5. See page 108, Important Changes During Year, for important new territory added and important rate increases or
decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts relating to unbilled revenue by accounts.
7. Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for Amount for Amount for Number for Line
Current Year Previous Year Current Year Previous Year No.
(d)(e)(f)(g)
1
5,457,378,298 5,280,429,207 485,475 470,804 2
3
6,034,805,124 5,751,179,676 87,130 85,737 4
3,200,734,385 3,099,273,213 120 120 5
27,303,850 29,292,943 4,083 3,733 6
7
8
9
14,720,221,657 **14,160,175,039 576,808 560,394 10
1,279,924,492 1,802,764,476 N/A N/A 11
16,000,146,149 15,962,939,515 576,808 560,394 12
13
* Includes <$1,128,089> in unbilled revenues.
** Includes 12,524,355 KWH relating to unbilled revenues.
Lines 11 through 21 are on an "allocated" basis.
Page 11a
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering..................................................................................................................................865,075$ 1,368,608$
5 (501) Fuel.............................................................................................................................................................................................................................91,112,173 114,327,024
6 (502) Steam Expenses..........................................................................................................................................................................................8,823,203 9,352,388
7 (503) Steam from Other Sources................................................................................................................................................................................
8 (Less) (504) Steam Transferred-Cr............................................................................................................................................................
9 (505) Electric Expenses..........................................................................................................................................................................................1,225,479 1,675,716
10 (506) Miscellaneous Steam Power Expenses..................................................................................................................................................8,147,229 9,404,861
11 (507) Rents........................................................................................................................................................................................................................208,271 211,847
12 (509) Allowances............................................................................................................................................................................................................................................
13 TOTAL Operation (Enter Total of lines 4 thru 12)....................................................................................................................110,381,430 136,340,443
14 Maintenance
15 (510) Maintenance Supervision and Engineering.......................................................................................................................................................(1,684)8,992
16 (511) Maintenance of Structures...........................................................................................................................................................................1,228,023 368,594
17 (512) Maintenance of Boiler Plant...........................................................................................................................................................8,516,751 8,111,607
18 (513) Maintenance of Electric Plant...........................................................................................................................................................2,573,376 3,007,255
19 (514) Miscellaneous Steam Plant...........................................................................................................................................................7,735,655 3,459,884
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19).............................................................................................................................20,052,121 14,956,332
21 TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 20).......................................................130,433,551 151,296,775
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering.................................................................................................................................................
25 (518) Fuel........................................................................................................................................................................................................................
26 (519) Coolants and Water...............................................................................................................................................................................................
27 (520) Steam Expenses...............................................................................................................................................................................................
28 (521) Steam from Other Sources...........................................................................................................................................................................
29 (Less) (522) Steam Transferred-Cr.....................................................................................................................................................................................
30 (523) Electric Expenses........................................................................................................................................................................................................
31 (524) Miscellaneous Nuclear Power Expenses......................................................................................................................................................................
32 (525) Rents.............................................................................................................................................................................................................................
33 TOTAL Operation (Enter Total of lines 24 thru 32)..................................................................................................................................
34 Maintenance
35 (528) Maintenance Supervision and Engineering............................................................................................................................................
36 (529) Maintenance of Structures...............................................................................................................................................................................
37 (530) Maintenance of Reactor Plant Equipment...........................................................................................................................................................
38 (531) Maintenance of Electric Plant...............................................................................................................................................................................
39 (532) Maintenance of Miscellaneous Nuclear Plant.................................................................................................................................................
40
41 TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering.......................................................................................................................................5,209,565 5,614,761
45 (536) Water for Power..............................................................................................................................................................................................................5,450,799 6,651,789
46 (537) Hydraulic Expenses....................................................................................................................................................................................................15,444,546 14,383,902
47 (538) Electric Expenses........................................................................................................................................................................................................1,708,881 2,021,101
48 (539) Miscellaneous Hydraulic Power Generation Expenses..................................................................................................................................4,719,626 4,742,157
49 (540) Rents..............................................................................................................................................................................................................294,344 248,038
50 TOTAL Operation (Enter Total of lines 44 thru 49)....................................................................................................32,827,761 33,661,747
Page 12
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Maintenance Supervision and Engineering..............................................................................................................................129,022$ 203,821$
54 (542) Maintenance of Structures...........................................................................................................................................................................953,612 674,572
55 (543) Maintenance of Reservoirs, Dams, and Waterways...............................................................................................................572,405 410,847
56 (544) Maintenance of Electric Plant.......................................................................................................................................................2,521,344 2,406,896
57 (545) Maintenance of Miscellaneous Hydraulic Plant...............................................................................................................2,944,067 2,901,479
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)..............................................................................................................7,120,450 6,597,616
59 TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and 58)39,948,211 40,259,363
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering..................................................................................................................................567,362 648,089
63 (547) Fuel........................................................................................................................................................................................................................81,460,446 50,690,020
64 (548) Generation Expenses.........................................................................................................................................................................................4,575,255 4,430,113
65 (549) Miscellaneous Other Power Generation Expenses..................................................................................................................................1,416,339 807,689
66 (550) Rents.........................................................................................................................................................................................................0 0
67 TOTAL Operation (Enter Total of lines 62 thru 66).........................................................................................................................88,019,403 56,575,912
68 Maintenance
69 (551) Maintenance Supervision and Engineering..................................................................................................................................0 0
70 (552) Maintenance of Structures.......................................................................................................................................................157,424 168,150
71 (553) Maintenance of Generating and Electric Plant...............................................................................................................69,702 130,051
72 (554) Maintenance of Miscellaneous Other Power Generation Plant...............................................................................................2,097,662 1,794,460
73 TOTAL Maintenance (Enter Total of lines 69 thru 72).................................................................................2,324,788 2,092,661
74 TOTAL Power Production Expenses-Other Power (Enter Total of lines 67 and 73).........................................90,344,191 58,668,573
75 E. Other Power Supply Expenses
76 (555) Purchased Power..........................................................................................................................................................................................369,574,908 279,813,774
77 (556) System Control and Load Dispatching.................................................................................................................................................340 6,072
78 (557) Other Expenses...................................................................................................................................................................................................(44,614,590)(28,409,031)
79 TOTAL Other Power Supply Expenses (Enter Total of lines 76 thru 78)............................................................324,960,659 251,410,815
80 TOTAL Power Production Expenses (Enter Total of lines 21, 41, 59, 74, and 79)..............................................585,686,613 501,635,526
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering........................................................................................................................................2,783,962 2,751,762
84 (561) Load Dispatching.........................................................................................................................................................................................5,087,881 4,671,622
85 (562) Station Expenses..............................................................................................................................................................................................2,909,865 2,676,133
86 (563) Overhead Line Expenses..........................................................................................................................................................................................1,012,935 850,414
87 (564) Underground Line Expenses................................................................................................................................................................................6,712,280 3,847,512
88 (565) Transmission of Electricity by Others.......................................................................................................................................................0 961,701
89 (566) Miscellaneous Transmission Expenses.................................................................................................................................................................4,385,743 3,857,810
90 (567) Rents..................................................................................................................................................................................................................................0 0
91 TOTAL Operation (Enter Total of lines 83 thru 90).........................................................................................................................22,892,667 19,616,954
92 Maintenance
93 (568) Maintenance Supervision and Engineering.......................................................................................................................................176,934 147,932
94 (569) Maintenance of Structures.................................................................................................................................................................1,467,327 1,307,782
95 (570) Maintenance of Station Equipment.............................................................................................................................................1,703,470 1,791,613
96 (571) Maintenance of Overhead Lines..................................................................................................................................................1,081,969 1,382,487
97 (572) Maintenance of Underground Lines...........................................................................................................................................................
98 (573) Maintenance of Miscellaneous Transmission Plant.............................................................................................................................2,443 467
99 (575) Transmission Market Administration - EIM.............................................................................................................................703,432 495,840
99 TOTAL Maintenance (Enter Total of lines 93 thru 98)...............................................................................................................5,135,576 5,126,120
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99).....................................................................................28,028,242 24,743,074
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering.......................................................................................................................................3,912,375 3,904,433
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IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
104 3. DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching...............................................................................................................................................................................................4,720,436$ 4,788,755$
106 (582) Station Expenses....................................................................................................................................................................................................1,511,068 1,609,593
107 (583) Overhead Line Expenses...............................................................................................................................................................................4,506,880 3,923,758
108 (584) Underground Line Expenses...............................................................................................................................................................................4,503,905 4,227,912
109 (585) Street Lighting and Signal System Expenses...................................................................................................................................537 8,074
110 (586) Meter Expenses...............................................................................................................................................................................................4,846,360 4,455,601
111 (587) Customer Installations Expenses.................................................................................................................................................................948,551 959,834
112 (588) Miscellaneous Distribution Expenses...........................................................................................................................................................................3,937,734 3,967,022
113 (589) Rents............................................................................................................................................................................................................................421,100 315,764
114 TOTAL Operation (Enter Total of lines 103 thru 113)....................................................................................................29,308,946 28,160,745
115 Maintenance
116 (590) Maintenance Supervision and Engineering.......................................................................................................................................................10,469 14,131
117 (591) Maintenance of Structures...............................................................................................................................................................................0 0
118 (592) Maintenance of Station Equipment...........................................................................................................................................................................3,902,335 3,686,674
119 (593) Maintenance of Overhead Lines..........................................................................................................................................................................................16,428,368 14,808,059
120 (594) Maintenance of Underground Lines...........................................................................................................................................................................588,903 525,085
121 (595) Maintenance of Line Transformers...........................................................................................................................................................55,701 46,985
122 (596) Maintenance of Street Lighting and Signal Systems...................................................................................................................252,270 258,117
123 (597) Maintenance of Meters.....................................................................................................................................................................................813,794 811,334
124 (598) Maintenance of Miscellaneous Distribution Plant...................................................................................................................91,906 131,300
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)........................................................................................................................................22,143,747 20,281,685
126 TOTAL Distribution Expenses (Enter Total of lines 114 and 125)...............................................................................................................51,452,693 48,442,430
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision.............................................................................................................................................................................................................800,134 677,412
130 (902) Meter Reading Expenses.....................................................................................................................................................................................1,535,472 1,479,985
131 (903) Customer Records and Collection Expenses.......................................................................................................................................................13,542,425 14,233,374
132 (904) Uncollectible Accounts..........................................................................................................................................................................................2,193,997 4,971,142
133 (905) Miscellaneous Customer Accounts Expenses...........................................................................................................................................................................401 123
134 TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133).............................................18,072,429 21,362,036
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision....................................................................................................................................................................................................745,616 693,641
138 (908) Customer Assistance Expenses................................................................................................................................................................................34,276,036 47,135,250
139 (909) Informational and Instructional Expenses.............................................................................................................................................284,745 286,906
140 (910) Miscellaneous Customer Service and Informational Expenses...................................................................................................................799,680 703,675
141 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 137 thru 140)...................................36,106,077 48,819,471
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision..................................................................................................................................................................................................................
145 (912) Demonstrating and Selling Expenses..........................................................................................................................................................................................- -
146 (913) Advertising Expenses...................................................................................................................................................................................................
147 (916) Miscellaneous Sales Expenses................................................................................................................................................................................
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147).........................................................................................................- -
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries................................................................................................................................................................83,409,198 83,132,875
152 (921) Office Supplies and Expenses...........................................................................................................................................................................13,372,062 13,029,732
153 (Less) (922) Administrative Expenses Transferred-Credit.............…….....….....................……(31,283,163)(28,448,941)
Page 14
IDAHO SUPPLEMENT
December 31, 2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed........................................................................................................................................7,474,551$ 6,502,270$
156 (924) Property Insurance................................................................................................................................................................................3,426,724 3,949,016
157 (925) Injuries and Damages...........................................................................................................................................................................6,191,531 5,762,351
158 (926) Employee Pensions and Benefits..................................................................................................................................................53,460,438 46,225,459
159 (927) Franchise Requirements................................................................................................................................................................................0 0
160 (928) Regulatory Commission Expenses.....................................................................................................................................................................4,857,719 4,000,063
161 (929) Duplicate Charges-Cr.........................................................................................................................................................................................
162 (930.1) General Advertising Expenses...............................................................................................................................................................................364,434 160,764
163 (930.2) Miscellaneous General Expenses...............................................................................................................................................................................3,905,591 3,528,596
164 (931) Rents.......................................................................................................................................................................................................................0 0
165 TOTAL Operation (Enter Total of lines 151 thru 164)........................................................................................................................145,179,084 137,842,186
166 Maintenance
167 (935) Maintenance of General Plant......................................................................................................................................................................7,499,770 7,160,659
168 TOTAL Admin and General Expenses (Enter Total of lines 165-167)……………………………………... 152,678,854 145,002,845
169 TOTAL Elec Op and Maint Exp (Total of 80, 100, 126, 134, 141, 148, 168)………………….. 872,024,907$ 790,005,381$
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of employees should be reported for the payroll period ending nearest to October 31,
or any payroll period ending 60 days before or after October 31.
2. If the respondent's payroll for the reporting period includes any special construction personnel, include
such employees on line 3, and show the number of such special construction employees in a footnote.
3. The number of employees assignable to the electric department from joint functions of combination utilities
may be determined by estimate, on the basis of employee equivalents. Show the estimated number of equiv-
alent employees attributed to the electric department from joint functions.
1 Payroll Period Ended (Date)..................................................................................................................................................December 31, 2021 December 31, 2020
2 Total Regular Full-Time Employees...................................................................................................................................1,983 1,932
3 Total Part-Time and Temporary Employees....................................................................................................................5 5
4 Total Employees................................................................................................................................................................................1,988 1,937
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IDAHO SUPPLEMENT